e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2009
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or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number:
001-33801
APPROACH RESOURCES
INC.
(Exact name of registrant as
specified in its charter)
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Delaware
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51-0424817
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification Number)
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One Ridgmar Centre
6500 West Freeway, Suite 800
Fort Worth, Texas
(Address of principal
executive offices)
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76116
(Zip Code)
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(Registrants telephone
number, including area code)
(817) 989-9000
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common stock, par value $0.01 per share
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NASDAQ Global Select Market
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Securities registered pursuant to Section 12(g) of the
Act: None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such
files). Yes o No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act.
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Large accelerated
filer o
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Accelerated
filer þ
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Non-accelerated
filer o
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Smaller reporting
company o
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Indicate by check mark whether the registrant is a shell company
(as defined in Exchange Act
Rule 12b-2). Yes o No þ
The aggregate market value of the voting and non-voting common
equity held by non-affiliates (excluding voting shares held by
officers and directors) as of June 30, 2009 was
$81.9 million. This amount is based on the closing price of
the registrants common stock on the NASDAQ Global Select
Market on that date.
The number of shares of the registrants common stock, par
value $0.01, outstanding as of March 5, 2010 was 20,998,389.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the registrants proxy statement for its 2010
annual meeting of stockholders are incorporated by reference in
Part III,
Items 10-14
of this report.
Certain exhibits previously filed with the Securities and
Exchange Commission are incorporated by reference into
Part IV of this report.
APPROACH
RESOURCES INC.
Unless the context otherwise indicates, all references in
this report to Approach, the Company,
we, us, our or
ours are to Approach Resources Inc. and its
subsidiaries. Unless otherwise noted, (i) all information
in this report relating to oil and natural gas reserves and the
estimated future net cash flows attributable to reserves is
based on estimates and is net to our interest, and (ii) all
information in this report relating to oil and natural gas
production is net to our interest. If you are not familiar with
the oil and gas terms used in this report, please refer to the
definitions of these terms under the caption
Glossary at the end of Item 15 of this
report.
TABLE OF
CONTENTS
ii
Cautionary
Statement Regarding Forward-Looking Statements
Various statements in this report, including those that express
a belief, expectation or intention, as well as those that are
not statements of historical fact, are forward-looking
statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, or the Securities Act, and
Section 21E of the Securities Exchange Act of 1934, as
amended, or the Exchange Act. The forward-looking statements may
include projections and estimates concerning the timing and
success of specific projects, typical well economics and our
future reserves, production, revenues, costs, income, capital
spending,
3-D seismic
operations, interpretation and results and obtaining permits and
regulatory approvals. When used in this report, the words
will, believe, intend,
expect, may, should,
anticipate, could, estimate,
plan, predict, project or
their negatives, other similar expressions or the statements
that include those words, are intended to identify
forward-looking statements, although not all forward-looking
statements contain such identifying words.
These forward-looking statements are largely based on our
expectations, 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. Although we believe such 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, managements assumptions about future events
may prove to be inaccurate. We caution all readers that the
forward-looking statements contained in this report are not
guarantees of future performance, and we cannot assure any
reader that such 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 section and elsewhere in this
report. All forward-looking statements speak only as of the date
of this report. We expressly disclaim all responsibility to
publicly update or revise any forward-looking statements as a
result of new information, future events or otherwise. These
cautionary statements qualify all forward-looking statements
attributable to us, or persons acting on our behalf. The risks,
contingencies and uncertainties relate to, among other matters,
the following:
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our business strategy;
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estimated quantities of oil and gas reserves;
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uncertainty of commodity prices in oil, gas and NGLs;
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global economic and financial market conditions;
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disruption of credit and capital markets;
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our financial position;
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our cash flow and liquidity;
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replacing our oil and gas reserves;
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our inability to retain and attract key personnel;
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uncertainty regarding our future operating results;
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uncertainties in exploring for and producing oil and gas;
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high costs, shortages, delivery delays or unavailability of
drilling rigs, equipment, labor or other services;
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disruptions to, capacity constraints in or other limitations on
the pipeline systems that deliver our gas and other processing
and transportation considerations;
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our inability to obtain additional financing necessary to fund
our operations and capital expenditures and to meet our other
obligations;
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competition in the oil and gas industry;
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iii
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marketing of oil, gas and NGLs;
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interpretation of
3-D seismic
data;
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exploitation of our current asset base or property acquisitions;
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the effects of government regulation and permitting and other
legal requirements;
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plans, objectives, expectations and intentions contained in this
report that are not historical; and
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other factors discussed under Item 1A. Risk
Factors in this report.
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iv
PART I
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Items 1.
and 2.
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Business
and Properties.
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General
We are an independent energy company engaged in the exploration,
development, production and acquisition of natural gas and oil
properties. We focus on natural gas and oil reserves in tight
sands and shale and have leasehold interests totaling
approximately 273,482 gross (196,634 net) acres as of
December 31, 2009. Our management and technical team has a
proven track record of finding and exploiting unconventional
reservoirs through advanced completion, fracturing and drilling
techniques. As the operator of all of our production and
estimated proved reserves, we have a high degree of control over
capital expenditures and other operating matters.
We currently operate or have interests in the following areas:
West
Texas
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Ozona Northeast (Wolfcamp, Canyon Sands, Strawn and Ellenburger)
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Cinco Terry (Wolfcamp, Canyon Sands and Ellenburger)
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East
Texas
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North Bald Prairie (Cotton Valley Sand, Bossier Shale and Cotton
Valley Lime)
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Northern
New Mexico
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El Vado East (Mancos Shale)
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Southwest
Kentucky
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Boomerang (New Albany Shale)
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At December 31, 2009, we owned working interests in 467
producing oil and gas wells, had estimated proved reserves of
approximately 218.9 Bcfe and were producing
21.7 MMcfe/d, based on production for December 2009. Our
2010 average daily production through February was
22 MMcfe/d.
At December 31, 2009, all of our proved reserves and
production were located in Ozona Northeast and Cinco Terry in
West Texas and in North Bald Prairie in East Texas. At year end
2009, our proved reserves were 77% natural gas, 43% proved
developed and had a reserve life index of over 20 years,
based on 2009 production of 8,808 MMcfe. In addition to our
producing wells, we have identified 1,311 total drilling
locations in Ozona Northeast, Cinco Terry and North Bald Prairie
at December 31, 2009, of which 385 are proved.
Approach was incorporated in 2002. Our common stock began
trading on the NASDAQ Global Market in the United States under
the symbol AREX on November 8, 2007. In
December 2008, our common stock became listed on the NASDAQ
Global Select Market, or NASDAQ. Our principal executive offices
are located at One Ridgmar Centre, 6500 West Freeway,
Suite 800, Fort Worth, Texas 76116. Our telephone
number is
(817) 989-9000.
Business
Strategy
Our objective is to build long-term stockholder value through
growth in reserves and production in a cost-efficient manner. We
intend to accomplish this objective by using a balanced program
of (1) developing our core properties, (2) completing
strategic acquisitions, (3) increasing our acreage,
reserves and production
1
through joint ventures, (4) operating as a low cost
producer, (5) maintaining financial flexibility, and
(6) exploring and exploiting our undeveloped properties.
The following are key elements of our strategy:
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Continue to develop our core properties. We
intend to develop further the significant remaining potential of
our Ozona Northeast, Cinco Terry and North Bald Prairie
properties, where we have identified 1,311 drilling locations.
We believe we have the technical expertise and operational
experience to maximize the value of these properties.
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Acquire strategic assets. We continually
review opportunities to acquire producing properties,
undeveloped acreage and drilling prospects. We focus
particularly on opportunities where we believe our reservoir
management and geological and operational expertise in
unconventional gas and oil properties will enhance value and
performance. We remain focused on unconventional resource
opportunities, but also look at conventional opportunities based
on individual project economics.
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Increase our land holdings, reserves and production through
farm-ins and drilling ventures. Our participation
in a farm-in and a joint drilling venture has allowed us to grow
our acreage position and reserves in Ozona Northeast
(49,850 gross and 43,553 net acres and 134.8 Bcfe
of proved reserves) and North Bald Prairie (8,006 gross and
4,711 net acres and 15.5 Bcfe of proved reserves).
Farm-ins, joint drilling or
drill-to-earn
ventures and similar agreements can allow us to develop
strategic, unconventional gas and oil properties for a
substantially lower initial investment than acquiring the
property outright.
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Operate our properties as a low cost
producer. We seek to minimize our operating costs
by concentrating our assets within geographic areas where we can
consolidate operating control and thus create operating
efficiencies. We operate all of our production and estimated
proved reserves and plan to continue to operate a substantial
portion of our producing properties in the future. Operating
control allows us to better manage timing and risk as well as
the cost of exploration and development, drilling and ongoing
operations.
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Maintain financial flexibility. At
December 31, 2009, we had $32.3 million in long-term
debt outstanding under our revolving credit facility, with a
borrowing base of $115 million, providing us with
significant financial flexibility to pursue our business
strategy. At February 28, 2010, we had $37.9 million
in long-term debt outstanding under our credit facility. We
intend to fund our 2010 capital expenditures, excluding any
acquisitions, primarily out of internally-generated cash flows
and, as necessary, borrowings under our revolving credit
facility.
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Exploit our undeveloped gas and oil
opportunities. We have an estimated
229,923 gross acres of undeveloped tight gas and shale gas
and oil inventory to explore and produce. On a long-term basis,
we believe we can add proved reserves and production from these
properties through advanced technologies, including horizontal
drilling and advanced fracing and completion techniques.
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2009
Activity
In December 2008, we announced a capital expenditure budget of
$43.8 million for 2009. Due to the extended decline of
natural gas prices, in March 2009 we announced that we would not
extend the contracts for our two remaining drilling rigs after
March 31, 2009, and we released these rigs during the first
week of April 2009. Overall for 2009, we increased production
slightly from 8,755 MMcfe (23.9 MMcfe/d) in 2008 to
8,808 MMcfe (24.1 MMcfe/d) in 2009. However, the
reduced drilling activity in the second and third quarters of
2009 and the natural decline of our tight gas fields resulted in
a decline in our average daily production from 28.1 MMcfe/d
for the three months ended March 31, 2009, to
21.6 MMcfe/d for the three months ended December 31,
2009.
A severe decline in natural gas, oil and NGL prices in 2009
adversely affected our results of operations. Our average
realized price for natural gas, oil and NGLs (before the effect
of commodity derivatives transactions) decreased 55.4%, 41.4%
and 37.7%, respectively, from 2008 to 2009. Despite this adverse
price environment, we were able to pay down our long-term debt
and increase our liquidity by over 40%, from $60.5 million
at December 31, 2008 to $85.4 million at
December 31, 2009. We define liquidity as funds
2
available under our credit facility plus year-end cash and cash
equivalents. At December 31, 2009, we had
$32.3 million in long-term debt outstanding under our
revolving credit facility, compared to $43.5 million in
long-term debt outstanding at December 31, 2008. The
following table summarizes our liquidity position at
December 31, 2009 compared to December 31, 2008:
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Years Ended December 31,
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2009
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2008
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(In thousands)
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Borrowing base
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$
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115,000
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$
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100,000
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Cash and cash equivalents
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2,685
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4,077
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Long-term debt
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(32,319
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(43,537
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Liquidity
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$
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85,366
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$
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60,540
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In addition, as the result of our drilling in Cinco Terry, in
2009 we were able to increase our estimated proved reserves, net
of production, by 4%, from 211,068 MMcfe at
December 31, 2008, to 218,928 MMcfe at
December 31, 2009. See Items 1. and 2. Business
and Properties Proved Oil and Gas Reserves for
more information regarding our estimated proved reserves.
We resumed drilling during September 2009. Also during the
fourth quarter of 2009, we began acquiring
3-D seismic
data across 128.4 square miles, or 82,176 acres, in
our Cinco Terry field.
Plans for
2010 Activity
At February 28, 2010, we were operating three rigs in our
core Permian Basin development areas: two in Cinco Terry and one
in Ozona Northeast. Our 2010 capital budget for development and
exploration expenditures is $53 million. As we did during
2008 and 2009, we will continue to monitor commodity prices,
operating expenses and drilling success to determine adjustments
to the 2010 capital budget. The 2010 capital budget allocates
$48.5 million to our core development properties in the
Permian Basin and includes two rigs in Cinco Terry and one rig
in Ozona Northeast until mid-year 2010, when we plan to add one
rig in Ozona Northeast. The 2010 capital budget also allocates
approximately $3.1 million to our exploratory prospects in
Northern New Mexico and Southwest Kentucky. We intend to
fund 2010 capital expenditures, excluding any acquisitions,
primarily out of internally-generated cash flows and, as
necessary, borrowings under our revolving credit facility.
We completed the acquisition of
3-D seismic
data across our Cinco Terry field in February 2010. Our
3-D seismic
data inventory now covers over 135,000 acres in the Permian
Basin. Interpretation of the data is expected to be complete by
June 2010.
We realize higher oil and NGL volumes in Cinco Terry than in
Ozona Northeast (where we have a contract that does not include
processing of NGLs) or North Bald Prairie (where substantially
all of our production is dry gas). Therefore, as we have
continued to develop Cinco Terry, we have increased the oil and
NGL component of our overall production and reserves. In
addition, our contract in Ozona Northeast expires in the first
quarter of 2011, after which time we will begin processing our
gas in Ozona Northeast. Excluding the effect of any future
acquisitions, we expect that continued development of Cinco
Terry in 2010 and beyond, along with processing gas in Ozona
Northeast in 2011 and beyond, will continue to increase the oil
and NGL component of our production and reserves in the future.
NGLs are sold by the gallon, and in reporting proved reserves
and production of NGLs, we convert NGLs to barrels of oil at the
rate of 42 gallons per one Bbl of oil.
3
The following table summarizes our overall production and
reserves over the past three years.
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Production
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Reserves
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Natural
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Oil &
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Natural
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Oil &
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Gas
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NGLs
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Gas
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NGLs
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(MMcf)
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(MBbls)
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(MMcf)
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(MBbls)
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December 31, 2009
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6,320
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415
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168,334
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8,432
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Percent
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72
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%
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28
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%
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77
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%
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23
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%
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December 31, 2008
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7,092
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277
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172,867
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6,367
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Percent
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81
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%
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19
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%
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82
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%
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18
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%
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December 31, 2007
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4,801
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84
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161,151
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3,208
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Percent
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90
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%
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10
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%
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89
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11
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Oil and
Gas Properties and Operations
West
Texas
Ozona
Northeast (Wolfcamp, Canyon Sands, Strawn and
Ellenburger)
The Ozona Northeast field in Crockett and Schleicher counties,
Texas, is our largest operating area on the basis of proved
reserves and production. We began operations in the field
through a farm-in arrangement in 2004, and have increased our
total acreage position to 49,850 gross (43,553 net) acres.
We own substantially all working interests in all depths of the
subsurface and have a net revenue interest of approximately 80%
in Ozona Northeast. We also operate approximately 150 miles
of gas gathering lines in the area. Beginning with our first
well in February 2004, through December 31, 2009, we have
drilled 312 successful wells out of 334 total wells drilled, for
a 93% success rate. As of December 31, 2009, we had
estimated proved reserves of 134.8 Bcfe in Ozona Northeast.
As of February 28, 2010, we had one rig operating in Ozona
Northeast.
Average daily production in 2009 was 14 MMcfe/d, or a total
of 5,096 MMcfe. Average daily production in 2010 (through
February) was 12.7 MMcfe/d. We have identified 660
additional drilling locations as of December 31, 2009, of
which 204 are proved.
Cinco
Terry (Wolfcamp, Canyon Sands and Ellenburger)
Since late 2005, we have leased and acquired options to lease
50,281 gross (23,818 net) acres in our Cinco Terry project,
two miles northwest of Ozona Northeast, to explore the Wolfcamp,
Canyon and Ellenburger formations. We have approximately a 52%
working interest and 39% net revenue interest in Cinco Terry.
Beginning with our first well in March 2006, through
December 31, 2009, we have drilled 87 successful wells out
of 100 total wells drilled, for an 87% success rate. As of
December 31, 2009, we had estimated proved reserves of
68.7 Bcfe in Cinco Terry. As of February 28, 2010, we
had two rigs operating in Cinco Terry.
Average daily production in 2009 was 9.3 MMcfe/d, or a
total of 3,394 MMcfe. Average daily production in 2010
(through February) was 8.6 MMcfe/d. We have identified 558
additional drilling locations as of December 31, 2009, of
which 157 are proved. We also own and operate seven miles of gas
gathering lines in the area.
East
Texas
North
Bald Prairie (Cotton Valley Sands, Bossier and Cotton Valley
Lime)
In July 2007, we entered into a joint drilling venture with
EnCana Oil & Gas (USA) Inc., or EnCana, in the East
Texas Cotton Valley/Bossier trend. As part of the joint venture,
we agreed to drill up to five wells at our cost to earn a 50%
working interest in the project. We began drilling operations in
August 2007. As of December 31, 2009, we had drilled and
completed 11 gross wells, including one well completed as a
saltwater disposal well. We have a 50% working interest and
approximately 40% net revenue interest. As of December 31,
2009, we had estimated proved reserves of 15.5 Bcfe in
North Bald Prairie. Average daily
4
production in 2009 was
0.9 MMcf/d,
or a total of 318 MMcf. Average daily production in 2010
(through February) was
0.7 MMcf/d.
We believe the potential exists for producing from multiple
zones in this area. Our primary targets are the Cotton Valley
Sand, Bossier Shale and Cotton Valley Lime, all unconventional
tight gas formations where we believe we can apply our
geological, technical and operational expertise to successfully
recover gas. Secondary targets include the shallower Rodessa,
Pettit and Travis Peak formations. We have identified 93
potential drilling locations as of December 31, 2009.
We currently have no rigs running in North Bald Prairie. As
previously reported, in December 2008, EnCana notified us that
it was exercising its right to become the operator of record for
joint interest wells in North Bald Prairie under the carry and
earning agreement between the parties. We have continued to
remain the operator of record pending payment by EnCana of joint
interest billings owed to us under the joint operating
agreement. In July 2009, our operating subsidiary filed a
lawsuit against EnCana for failure to pay joint interest
billings under the joint operating agreement. This proceeding is
described in more detail in Part I, Item 3,
Legal Proceedings, and Note 10 to our
consolidated financial statements in this report. The joint
operating agreement, or JOA, allows either party to propose
wells in the drilling project. In addition, we have re-leased or
renewed approximately 2,461 net acres in the project at
working interests of 100% as such acreage has expired or come up
for renewal and EnCana has elected not to participate in such
leases. We will continue to monitor commodity prices and offset
acreage development to determine when to resume drilling in
North Bald Prairie.
Northern
New Mexico
El Vado
East (Mancos Shale)
Our El Vado East prospect is a 90,357 gross (79,793 net)
acre Mancos Shale play located in the Chama Basin in
Northern New Mexico in proximity to several productive fields,
including the Puerto Chiquito West, Puerto Chiquito East and the
Boulder fields. Our primary objective in El Vado East is the
Mancos Shale at 2,000 to 3,000 feet. We have a 90% working
interest and a net revenue interest of approximately 72% in our
El Vado East prospect. At December 31, 2009, we had no
estimated proved reserves recorded for El Vado East.
Since Rio Arriba County, or the County, imposed a moratorium on
permits for new oil and gas development on private lands in the
County in April 2008, regulatory proceedings and an inability to
timely obtain permits have delayed our drilling plans in El Vado
East. In May 2009, the County lifted the drilling moratorium and
enacted an oil and gas ordinance regulating oil and gas
operations on private lands in the County. In addition to
obtaining permits to drill from the State of New Mexico, we are
now required to obtain special use permits from the County for
drilling locations in El Vado East. The force
majeure provisions of our mineral lease for El Vado East
provide that if our drilling operations are delayed or prevented
as a result of a governmental or regulatory order or by failure
to obtain permits, then our commitments under the lease,
including our initial drilling commitment of eight wells, will
be extended for the period of force majeure, as long as the
primary term of the lease is not extended by more than four
years, or April 2013. We have invoked our right to assert force
majeure under the lease and have received conditional approvals
from the State for permits to drill 11 locations. We also have
applied for special use permits from the County to drill eight
locations. See Items 1. and 2. Business and
Properties Regulation New Mexico
for additional information on our New Mexico lease and the
delays in drilling in New Mexico.
Southwest
Kentucky
Boomerang
(New Albany Shale)
Our Boomerang prospect is a 74,988 gross (44,759 net)
acre New Albany Shale play located in Southwest Kentucky in
the Illinois Basin. We have a 60% working interest and a net
revenue interest of approximately 50%. Our capital budget for
2010 provides for the completion of two, previously-drilled
wells in the New Albany Shale during 2010. Our technical team is
also analyzing data from offset wells drilled to
5
deeper formations and evaluating the purchase of
2-D seismic
data to help define potentially deeper target zones. At
December 31, 2009, we had no estimated proved reserves
recorded for Boomerang.
Northeast
British Columbia
Montney
Tight Gas and Doig Shale
In August 2007, we acquired a non-operating, working interest
ranging from 11.9% to 25% in a lease acquisition and drilling
project targeting unconventional gas reserves in the emerging
Montney tight gas and Doig Shale play in Northeast British
Columbia.
We review our long-lived assets to be held and used, including
proved and unproved oil and gas properties, accounted for under
the successful efforts method of accounting. Based on the review
of the recoverability of the carrying value of our unproved
properties in Northeast British Columbia, we have recorded an
impairment expense from a write-off of $3 million, related
to all of our remaining carrying costs in this project. At
December 31, 2009, we had no estimated proved reserves
recorded for Northeast British Columbia, and no plans to develop
the project. Acreage amounts in this report exclude Northeast
British Columbia.
Proved
Oil and Gas Reserves
Proved
Reserves Reporting
On December 31, 2008, the Securities and Exchange
Commission, or the SEC, released a Final Rule, Modernization
of Oil and Gas Reporting, approving revisions designed to
modernize oil and gas reserve reporting requirements. The new
reserve rules are effective for our financial statements for the
year ended December 31, 2009 and our 2009 year-end
proved reserve estimates. The most significant revisions to the
reporting requirements include:
|
|
|
|
|
Commodity prices. Economic producibility of
reserves is now based on the unweighted, arithmetic average of
the closing price on the first day of the month for the
12-month
period prior to fiscal year end, unless prices are defined by
contractual arrangements;
|
|
|
|
Undeveloped oil and gas reserves. Reserves may
be classified as proved undeveloped for undrilled
areas beyond one offsetting drilling unit from a producing well
if there is reasonable certainty that the quantities will be
recovered;
|
|
|
|
Reliable technology. The rules now permit the
use of new technologies to establish the reasonable certainty of
proved reserves if those technologies have been demonstrated
empirically to lead to reliable conclusions about reserves
volumes;
|
|
|
|
Unproved reserves. Probable and possible
reserves may be disclosed separately on a voluntary basis;
|
|
|
|
Preparation of reserves estimates. Disclosure
is required regarding the internal controls used to assure
objectivity in the reserves estimation process and the
qualifications of the technical person primarily responsible for
preparing reserves estimates; and
|
|
|
|
Third party reports. We are now required to
file the report of any third party used to prepare or audit
reserves our estimates.
|
We adopted the rules effective December 31, 2009, as
required by the SEC.
Proved
Reserves Table
The following table sets forth summary information regarding our
estimated proved reserves as of December 31, 2009. See
Note 12 to our consolidated financial statements for
additional information. Our estimated total proved reserves of
natural gas, oil and NGLs as of December 31, 2009 were
218.9 Bcfe. The 2009 reserves are composed of 77% natural
gas and 23% oil, condensate and NGLs. The proved developed
portion of total proved reserves at year end 2009 was 43%. We
determined the natural gas equivalent of oil,
6
condensate and NGLs by using a conversion ratio of six Mcf of
natural gas to one Bbl of oil, condensate or NGLs.
The standardized measure of discounted future net cash flows for
our proved reserves at December 31, 2009 was
$80 million. The
PV-10 of our
estimated proved reserves at December 31, 2009, was
$128.9 million.
Summary
of Oil and Gas Reserves as of Fiscal-Year End
Based on Average Fiscal-Year Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserves
|
|
|
Natural
|
|
Oil &
|
|
|
|
|
Gas
|
|
NGLs
|
|
Total
|
Reserves Category
|
|
(MMcf)
|
|
(MBbls)
|
|
(MMcfe)
|
|
PROVED
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed:
|
|
|
|
|
|
|
|
|
|
|
|
|
Ozona Northeast
|
|
|
61,265
|
|
|
|
463
|
|
|
|
64,043
|
|
Cinco Terry
|
|
|
11,827
|
|
|
|
2,655
|
|
|
|
27,757
|
|
North Bald Prairie
|
|
|
1,712
|
|
|
|
|
|
|
|
1,712
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
74,804
|
|
|
|
3,118
|
|
|
|
93,512
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped:
|
|
|
|
|
|
|
|
|
|
|
|
|
Ozona Northeast
|
|
|
65,350
|
|
|
|
896
|
|
|
|
70,724
|
|
Cinco Terry
|
|
|
14,408
|
|
|
|
4,418
|
|
|
|
40,920
|
|
North Bald Prairie
|
|
|
13,772
|
|
|
|
|
|
|
|
13,772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
93,530
|
|
|
|
5,314
|
|
|
|
125,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL PROVED at December 31, 2009
|
|
|
168,334
|
|
|
|
8,432
|
|
|
|
218,928
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of New Proved Reserves Reporting Requirements
The new reserve rules resulted in the use of lower prices for
natural gas, oil and NGLs than would have resulted under the
previous reporting requirements. Under the previous reserve
rules, our estimated total proved reserves of natural gas, oil
and NGLs would have been 231.2 Bcfe. Therefore, the effect
of the new reserve rules was a negative revision of
12.3 Bcfe.
The new reserve rules limit the recording and maintaining of
proved undeveloped reserves locations to those scheduled to be
drilled within the next five years, unless the specific
circumstances justify a longer time. This new reserve rules did
not affect our estimates of proved reserves.
Preparation
of Proved Reserves Estimates
Internal
Controls Over Preparation of Proved Reserves Estimates
Our policies regarding internal controls over the recording of
reserve estimates require reserve estimates to be in compliance
with SEC rules, regulations and guidance and prepared in
accordance with generally accepted petroleum engineering
principles. Our Manger of Reservoir Engineering, John J.
Marting, P.E., is the individual responsible for overseeing the
preparation of our reserve estimates and for internal compliance
of our reserve estimates with SEC rules, regulations and
generally accepted petroleum engineering principles.
Mr. Marting has a Bachelor of Science degree in Petroleum
Engineering (Cum Laude) from the University of Missouri-Rolla
and over 30 years of industry experience. Mr. Marting
reports directly to our Chief Executive Officer. Our senior
management, including our Chief Executive Officer and Chief
Financial Officer, reviews our reserves estimates before these
estimates are finalized and disclosed in a public filing or
presentation.
For the years ended December 31, 2009, 2008 and 2007, we
engaged DeGolyer and MacNaughton, independent petroleum
engineers, to prepare independent estimates of the extent and
value of the proved
7
reserves associated with certain of our oil and gas properties.
See Third Party Reports below for further information
regarding DeGolyer & MacNaughtons report.
Technologies
Used in Preparation of Proved Reserves Estimates
Estimates of reserves were prepared by the use of standard
geological and engineering methods generally accepted by the
petroleum industry. The method or combination of methods used in
the analysis of each reservoir was tempered by experience with
similar reservoirs, stage of development, quality and
completeness of basic data and production history.
When applicable, the volumetric method was used to estimate the
original oil in place, or OOIP, and the original gas in place,
or OGIP. Structure and isopach maps were constructed to estimate
reservoir volume. Electrical logs, radioactivity logs, core
analyses and other available data were used to prepare these
maps as well as to estimate representative values for porosity
and water saturation. When adequate data were available and when
circumstances justified, material balance and other engineering
methods were used to estimate OOIP or OGIP.
Estimates of ultimate recovery were obtained after applying
recovery factors to OOIP or OGIP. These recovery factors were
based on consideration of the type of energy inherent in the
reservoirs, analyses of the petroleum, the structural positions
of the properties and the production histories. When applicable,
material balance and other engineering methods were used to
estimate recovery factors. An analysis of reservoir performance,
including production rate, reservoir pressure and gas-oil ratio
behavior, was used in the estimation of reserves.
Because our proved reserves are located in depletion-type
reservoirs and reservoirs whose performance demonstrates a
reliable decline in producing-rate trends, reserves were also
estimated by the application of appropriate decline curves or
other performance relationships. In the analyses of
production-declining curves, reserves were estimated only to the
limits of economic production or to the limit of the production
licenses or leases as appropriate.
Third
Party Reports
For the years ended December 31, 2009, 2008 and 2007, we
engaged DeGolyer and MacNaughton, independent, third-party
reserves engineers, to prepare estimates of the extent and value
of the proved reserves of certain of our oil and gas properties.
The estimates for 2009, 2008 and 2007 included a detailed review
of our Ozona Northeast, Cinco Terry and North Bald Prairie
fields, or 100% of our total proved reserves. DeGolyer and
MacNaughtons report for 2009 is included as
Exhibit 99.1 to this annual report on
Form 10-K.
Reserves
Sensitivity Analysis
The following table provides an estimate of our proved reserves
based on a Current Price Case calculated under the
new reserve rules, and a Previous Price Case
calculated under the previous reserve rules.
Sensitivity
of Reserves to Prices by Principal Product Type and Price
Scenario
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves
|
|
|
|
|
Natural
|
|
Oil &
|
|
|
|
|
|
|
Gas
|
|
NGLs
|
|
Total
|
|
|
Price Case
|
|
(MMcf)
|
|
(MBbls)
|
|
(MMcfe)
|
|
PV-10
|
|
Current Price Case
|
|
|
168,334
|
|
|
|
8,432
|
|
|
|
218,928
|
|
|
$
|
128,936
|
|
Previous Price Case
|
|
|
178,354
|
|
|
|
8,806
|
|
|
|
231,190
|
|
|
$
|
317,440
|
|
Proved reserve volumes and
PV-10 in the
Current Price Case were estimated based on the unweighted,
arithmetic average of the closing price on the first day of each
month for the
12-month
period prior to December 31, 2009 for natural gas, oil and
NGLs. Natural gas volumes were calculated based on the average
Henry Hub spot price of $3.87 per MMBtu. Oil volumes were
calculated based on the average West Texas
8
Intermediate, or WTI, posted price of $61.04 per Bbl. NGL
volumes were calculated based on the average price received on
the first day of each month during 2009 of $27.20 per Bbl. All
prices were adjusted for energy content, quality and basis
differentials by field and were held constant through the lives
of the properties.
Proved reserve volumes and
PV-10 in the
Previous Price Case were estimated based on the posted spot
price as of December 31, 2009, for natural gas, oil and
NGLs. Natural gas volumes were calculated based on the Henry Hub
spot price of $5.79 per MMBtu. Oil volumes were calculated based
on the WTI posted price of $76.00 per Bbl. NGL volumes were
calculated based on the Mont Belvieu posted price of $42.94 per
Bbl. All prices were adjusted for energy content, quality and
basis differentials by field and were held constant through the
lives of the properties.
PV-10 is our
estimate of the present value of future net revenues from proved
oil and gas reserves after deducting estimated production and ad
valorem taxes, future capital costs and operating expenses, but
before deducting any estimates of future income taxes.
PV-10 is a
non-GAAP, financial measure and generally differs from the
standardized measure of discounted future net cash flows, the
most directly comparable GAAP financial measure, because it does
not include the effects of income taxes on future cash flows.
PV-10 should
not be considered as an alternative to the standardized measure
of discounted future net cash flows as computed under GAAP.
The following table shows our reconciliation of our
PV-10 to the
standardized measure of discounted future net cash flows (the
most directly comparable measure calculated and presented in
accordance with GAAP). The estimated future net revenues are
discounted at an annual rate of 10% to determine their
present value.
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
Previous
|
|
As of December 31, 2009
|
|
Price Case
|
|
|
Price Case
|
|
|
|
(In thousands)
|
|
|
PV-10
|
|
$
|
128,936
|
|
|
$
|
317,440
|
|
Less income taxes:
|
|
|
|
|
|
|
|
|
Undiscounted future income taxes
|
|
|
(88,796
|
)
|
|
|
(256,144
|
)
|
10% discount factor
|
|
|
39,851
|
|
|
|
139,625
|
|
|
|
|
|
|
|
|
|
|
Future discounted income taxes
|
|
|
(48,945
|
)
|
|
|
(116,519
|
)
|
Standardized measure of discounted future net cash flows
|
|
$
|
79,991
|
|
|
$
|
200,921
|
|
|
|
|
|
|
|
|
|
|
We believe
PV-10 to be
an important measure for evaluating the relative significance of
our oil and gas properties and 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. Because there are many unique
factors that can impact an individual company when estimating
the amount of future income taxes to be paid, we believe the use
of a pre-tax measure is valuable for evaluating our company. We
believe that most other companies in the oil and gas industry
calculate
PV-10 on the
same basis.
Proved
Undeveloped Reserves
As of December 31, 2009, we had 125.4 Bcfe of proved
undeveloped reserves, or PUDs, which is an increase of
16.7 Bcfe or 15.3%, compared with 108.8 Bcfe of PUDs
at December 31, 2008. Approximately 89% of our PUDs at
December 31, 2009 were associated with our core development
properties in the Permian Basin: Ozona Northeast (56%) and Cinco
Terry (33%). The remaining 11% of our PUDs at year-end 2009 were
associated with our North Bald Prairie field in East Texas.
We added 25.7 Bcfe of PUDs in 2009 through our drilling
program, consisting of 20.6 Bcfe of extensions and
discoveries in Cinco Terry and 5.1 Bcfe of extensions and
discoveries in Ozona Northeast. Partially offsetting extensions
and discoveries was a negative revision of 3.5 Bcfe in
Ozona Northeast and North Bald Prairie due to lower commodity
prices. We also removed 5.6 Bcfe of PUDs due to performance
revisions primarily attributable to North Bald Prairie.
9
We invested approximately $3.5 million to convert
1 Bcfe of PUDs in Cinco Terry to proved developed in 2009.
Estimated future development costs relating to the development
of PUDs are projected to be approximately $59.8 million in
2010, $55.4 million in 2011 and $45.6 million in 2012.
All PUDs are scheduled to be drilled before the end of 2014.
We have 2.6 Bcfe of PUDs, or approximately 1% of our total
proved reserves, that have been booked for five years or longer.
These reserves are located in Ozona Northeast. As discussed in
Items 1. and 2. Business and Properties
2009 Activity, of this report, we reduced our drilling
activity in 2009 in response to a sharp decline in natural gas
prices. As of February 28, 2010, we had resumed drilling in
Ozona Northeast with one rig. We plan to add a second rig in
Ozona Northeast by mid-year 2010 and drill a total of
36 gross wells in 2010. Despite the expected increase in
drilling in Ozona Northeast in 2010, the volume of PUDs in Ozona
Northeast that will have been booked for five years or longer at
December 31, 2010, will increase from December 31,
2009 and, depending on the timing and selection of locations to
be drilled in Ozona Northeast in 2010, such increase might be
material. We have a history of significant development activity
in Ozona Northeast, as we have drilled over 330 gross (over
250 net) wells there since our first well in February 2004, and
we intend to continue the development of PUDs in Ozona Northeast
over time.
Oil and
Gas Production, Production Prices and Production Costs
The following table sets forth summary information regarding
natural gas, oil and NGL production, average sales prices and
average production costs, by geographic area, for the last three
years. We determined the natural gas equivalent of oil,
condensate and NGLs by using a conversion ratio of six Mcf of
natural gas to one Bbl of oil, condensate or NGLs.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production
|
|
|
Natural Gas
|
|
Oil
|
|
NGLs
|
|
Total
|
|
|
(MMcf)
|
|
(MBbl)
|
|
(MBbl)
|
|
(MMcfe)
|
|
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ozona Northeast
|
|
|
4,654
|
|
|
|
74
|
|
|
|
|
|
|
|
5,096
|
|
Cinco Terry
|
|
|
1,348
|
|
|
|
132
|
|
|
|
209
|
|
|
|
3,394
|
|
North Bald Prairie
|
|
|
318
|
|
|
|
|
|
|
|
|
|
|
|
318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
6,320
|
|
|
|
206
|
|
|
|
209
|
|
|
|
8,808
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ozona Northeast
|
|
|
5,567
|
|
|
|
68
|
|
|
|
|
|
|
|
5,976
|
|
Cinco Terry
|
|
|
1,078
|
|
|
|
107
|
|
|
|
102
|
|
|
|
2,332
|
|
North Bald Prairie
|
|
|
447
|
|
|
|
|
|
|
|
|
|
|
|
447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
7,092
|
|
|
|
175
|
|
|
|
102
|
|
|
|
8,755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ozona Northeast
|
|
|
4,719
|
|
|
|
58
|
|
|
|
|
|
|
|
5,067
|
|
Cinco Terry
|
|
|
82
|
|
|
|
14
|
|
|
|
12
|
|
|
|
238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
4,801
|
|
|
|
72
|
|
|
|
12
|
|
|
|
5,305
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
Average Sales Price(1)
|
|
|
Cost
|
|
|
|
Natural Gas
|
|
|
Oil
|
|
|
NGLs
|
|
|
Total
|
|
|
$/Per
|
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
(Per Bbl)
|
|
|
(Per Mcfe)
|
|
|
Mcfe(2)
|
|
|
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ozona Northeast
|
|
$
|
3.79
|
|
|
$
|
59.96
|
|
|
$
|
|
|
|
$
|
4.29
|
|
|
$
|
0.69
|
|
Cinco Terry
|
|
|
3.37
|
|
|
|
53.85
|
|
|
|
28.32
|
|
|
|
5.18
|
|
|
|
0.65
|
|
North Bald Prairie
|
|
|
3.78
|
|
|
|
|
|
|
|
|
|
|
|
3.78
|
|
|
|
1.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3.70
|
|
|
$
|
54.97
|
|
|
$
|
28.32
|
|
|
$
|
4.61
|
|
|
$
|
0.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ozona Northeast
|
|
$
|
8.54
|
|
|
$
|
102.46
|
|
|
$
|
|
|
|
$
|
9.11
|
|
|
$
|
0.74
|
|
Cinco Terry
|
|
|
7.37
|
|
|
|
89.23
|
|
|
|
45.46
|
|
|
|
9.49
|
|
|
|
0.66
|
|
North Bald Prairie
|
|
|
7.42
|
|
|
|
|
|
|
|
|
|
|
|
7.42
|
|
|
|
1.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
8.29
|
|
|
$
|
93.79
|
|
|
$
|
45.46
|
|
|
$
|
9.12
|
|
|
$
|
0.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ozona Northeast
|
|
$
|
7.00
|
|
|
$
|
69.98
|
|
|
$
|
|
|
|
$
|
7.32
|
|
|
$
|
0.52
|
|
Cinco Terry
|
|
|
5.82
|
|
|
|
83.58
|
|
|
|
46.25
|
|
|
|
8.55
|
|
|
|
0.79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
6.98
|
|
|
$
|
70.31
|
|
|
$
|
46.25
|
|
|
$
|
7.37
|
|
|
$
|
0.53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Average sales price for 2009, 2008 and 2007 excludes the
positive effect of commodity derivatives of $1.66/Mcfe,
$0.34/Mcfe and $0.89/Mcfe, respectively. |
|
(2) |
|
Production cost per Mcfe is composed of lease operating expenses
excluding ad valorem taxes. Production cost per Mcfe also
excludes severance and production taxes. |
Producing
Wells
The following table sets forth the number of producing wells in
which we owned a working interest at December 31, 2009.
Wells are classified as natural gas or oil according to their
predominant production stream.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
Oil
|
|
Total
|
|
Average
|
|
|
Wells
|
|
Wells
|
|
Wells
|
|
Working
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Interest
|
|
Ozona Northeast
|
|
|
371
|
|
|
|
361
|
|
|
|
1
|
|
|
|
1
|
|
|
|
372
|
|
|
|
362
|
|
|
|
97
|
%
|
Cinco Terry
|
|
|
76
|
|
|
|
38
|
|
|
|
10
|
|
|
|
5
|
|
|
|
86
|
|
|
|
43
|
|
|
|
50
|
%
|
North Bald Prairie
|
|
|
9
|
|
|
|
4.5
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
4.5
|
|
|
|
50
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
456
|
|
|
|
403.5
|
|
|
|
11
|
|
|
|
6
|
|
|
|
467
|
|
|
|
409.5
|
|
|
|
88
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
Drilling
Activity
The following table sets forth information on our drilling
activity for the last three years. 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2009
|
|
2008
|
|
2007
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
28.0
|
|
|
|
16.0
|
|
|
|
83.0
|
|
|
|
54.5
|
|
|
|
51.0
|
|
|
|
46.0
|
|
Non-productive
|
|
|
4.0
|
|
|
|
2.0
|
|
|
|
11.0
|
|
|
|
7.5
|
|
|
|
5.0
|
|
|
|
4.0
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-productive
|
|
|
|
|
|
|
|
|
|
|
2.0
|
|
|
|
0.5
|
|
|
|
1.0
|
|
|
|
0.7
|
|
Total wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
28.0
|
|
|
|
16.0
|
|
|
|
83.0
|
|
|
|
54.5
|
|
|
|
51.0
|
|
|
|
46.0
|
|
Non-productive
|
|
|
4.0
|
|
|
|
2.0
|
|
|
|
13.0
|
|
|
|
8.0
|
|
|
|
6.0
|
|
|
|
4.7
|
|
Of the 28 gross productive wells drilling 2009, four (three
net) wells were waiting on completion at December 31, 2009,
and have since been completed as producers.
Of the 11 gross development non-productive wells drilled in
2008, one well was completed as a saltwater disposal well in
North Bald Prairie during 2009. The two gross exploratory,
non-productive wells drilled in 2008 were drilled by the
Canadian operator of our Northeast British Columbia project.
Although a well may be classified as productive upon completion,
future changes in oil and gas prices, operating costs and
production may result in the well becoming uneconomical.
Acreage
The following table summarizes our developed and undeveloped
acreage as of December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acres
|
|
Undeveloped Acres
|
|
Total Acres
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Ozona Northeast
|
|
|
29,760
|
|
|
|
28,944
|
|
|
|
20,090
|
|
|
|
14,609
|
|
|
|
49,850
|
|
|
|
43,553
|
|
Cinco Terry
|
|
|
10,318
|
|
|
|
5,263
|
|
|
|
39,963
|
|
|
|
18,555
|
|
|
|
50,281
|
|
|
|
23,818
|
|
North Bald Prairie
|
|
|
3,481
|
|
|
|
1,687
|
|
|
|
4,525
|
|
|
|
3,024
|
|
|
|
8,006
|
|
|
|
4,711
|
|
El Vado East
|
|
|
|
|
|
|
|
|
|
|
90,357
|
|
|
|
79,793
|
|
|
|
90,357
|
|
|
|
79,793
|
|
Boomerang
|
|
|
|
|
|
|
|
|
|
|
74,988
|
|
|
|
44,759
|
|
|
|
74,988
|
|
|
|
44,759
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
43,559
|
|
|
|
35,894
|
|
|
|
229,923
|
|
|
|
160,740
|
|
|
|
273,482
|
|
|
|
196,634
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
Undeveloped
Acreage Expirations
The following table sets forth the number of gross and net
undeveloped acres as of December 31, 2009 that will expire
over the next three years by project area unless production is
established prior to the expiration dates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
2011
|
|
2012
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Ozona Northeast
|
|
|
|
|
|
|
14
|
|
|
|
9,983
|
|
|
|
11,620
|
|
|
|
6,321
|
|
|
|
2,410
|
|
Cinco Terry
|
|
|
7,192
|
|
|
|
4,172
|
|
|
|
11,642
|
|
|
|
6,183
|
|
|
|
7,833
|
|
|
|
5,002
|
|
North Bald Prairie
|
|
|
1,050
|
|
|
|
563
|
|
|
|
|
|
|
|
|
|
|
|
335
|
|
|
|
254
|
|
El Vado East
|
|
|
90,357
|
|
|
|
79,793
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Boomerang
|
|
|
6,777
|
|
|
|
4,066
|
|
|
|
146
|
|
|
|
88
|
|
|
|
725
|
|
|
|
435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
105,376
|
|
|
|
88,608
|
|
|
|
21,771
|
|
|
|
17,891
|
|
|
|
15,214
|
|
|
|
8,101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped acreage in our Boomerang prospect assumes the
exercise of options to extend the current primary terms by four
to five additional years (beginning June 2010 through May
2012) on 67,340 gross (40,171 net) acres. Options to
extend 58,548 gross (35,027 net) acres have an exercise
price of $2 per year per net acre for five total available
years. Options to extend 5,860 gross (3,480 net) acres have
an exercise price of $6 per year per net acre for five total
available years. Options to extend 1,650 gross (894 net)
acres have an exercise price of $7 per year per net acre for
five total available years. Options to extend the remaining
1,282 gross (769 net) acres have a weighted average
exercise price of $38 per net acre for four to five total
available years.
Undeveloped acreage in our El Vado East prospect is subject to
an eight-well drilling commitment during the primary term of the
mineral lease, which expired in April 2009. As of the filing of
this annual report on
Form 10-K,
the primary term was extended by force majeure under the lease,
up to April 2013. If we meet the drilling commitment (as
extended by force majeure), we will have two options to extend
the primary term by one year each for $15 per net acre, for a
total extension of two years at $30 per net acre. If we are not
able to meet the drilling commitment, during the extended
primary term, and we are otherwise not able to negotiate
appropriate extensions under the lease, the lease will expire.
See Items 1. and 2. Business and
Properties Regulation New Mexico
for additional information on our New Mexico lease and the
delays in drilling in New Mexico.
Markets
and Customers
The revenues generated by our operations are highly dependent
upon the prices of, and supply and demand for, oil and gas. The
price we receive for our oil and gas production depends on
numerous factors beyond our control, including seasonality, the
condition of the United States and global economies,
particularly in the manufacturing sectors, political conditions
in other oil and gas producing countries, the extent of domestic
production and imports of oil and gas, the proximity and
capacity of gas pipelines and other transportation facilities,
supply and demand for oil and gas, the marketing of competitive
fuels and the effects of federal, state and local regulation.
The oil and gas industry also competes with other industries in
supplying the energy and fuel requirements of industrial,
commercial and individual consumers.
During the year ended December 31, 2009, Ozona Pipeline
Energy Company, which we refer to as Ozona Pipeline, WTG
Benedum/Belvan Partners, LP and Shell Trading U.S. Company,
which we refer to as Shell, were our most significant
purchasers, accounting for approximately 43.3%, 26.1% and 22.4%,
respectively, of our total 2009 oil and gas sales excluding
realized commodity derivative settlements.
Commodity
Derivative Activity
We enter into financial swaps and collars to mitigate portions
of the risk of market price fluctuations related to future oil
and gas production.
13
All derivative instruments are recorded on the balance sheet at
fair value. Changes in the derivatives fair value are
currently recognized in the statement of operations unless
specific commodity derivative accounting criteria are met and
contracts have been designated as cash flow hedge instruments.
For qualifying cash-flow commodity derivatives, the gain or loss
on the derivative is deferred in accumulated other comprehensive
(loss) income to the extent the commodity derivative is
effective. The ineffective portion of the commodity derivative
is recognized immediately in the statement of operations. Gains
and losses on commodity derivative instruments included in
accumulated other comprehensive (loss) income are reclassified
to oil and gas sales revenue in the period that the related
production is delivered. Derivative contracts that do not
qualify for commodity derivative accounting treatment are
recorded as derivative assets and liabilities at fair value in
the balance sheet, and the associated unrealized gains and
losses are recorded as current income or expense in the
statement of operations.
Historically, we have not designated our derivative instruments
as cash-flow commodity derivatives. We record our open
derivative instruments at fair value on our consolidated balance
sheets as either unrealized gains or losses on commodity
derivatives. We record changes in such fair value in earnings on
our consolidated statements of operations under the caption
entitled unrealized (loss) gain on commodity
derivatives.
Title to
Properties
Our properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and
other burdens, including other mineral encumbrances and
restrictions. We do not believe that any of these burdens
materially interfere with our use of the properties in the
operation of our business.
We believe that we have generally satisfactory title to or
rights in all of our producing properties. As is customary in
the oil and gas industry, we make a general investigation of
title at the time we acquire undeveloped properties. We receive
title opinions of counsel before we commence drilling
operations. We believe that we have satisfactory title to all of
our other assets. Although title to our properties is subject to
encumbrances in certain cases, we believe that none of these
burdens will materially detract from the value of our properties
or from our interest therein or will materially interfere with
our use of the properties in the operation of our business.
Competition
The oil and gas industry is highly competitive, and we compete
for prospective properties, producing properties and personnel
with a substantial number of other companies that have greater
resources. Many of these companies explore for, produce and
market oil and gas, carry on refining operations and market the
resultant products on a worldwide basis. The primary areas in
which we encounter substantial competition are in locating and
acquiring desirable leasehold acreage for our drilling and
development operations, locating and acquiring attractive
producing oil and gas properties, attracting highly-skilled
personnel and obtaining purchasers and transporters of the oil
and gas we produce. We also face competition from alternative
fuel sources, including coal, heating oil, imported LNG, nuclear
and other nonrenewable fuel sources, and renewable fuel sources
such as wind, solar, geothermal, hydropower and biomass.
Competitive conditions may also be substantially affected by
various forms of energy legislation
and/or
regulation considered from time to time by the United States
government. However, it is not possible to predict the nature of
any such legislation or regulation that may ultimately be
adopted or its effects upon our future operations. Such laws and
regulations may, however, substantially increase the costs of
exploring for, developing or producing oil and gas and may
prevent or delay the commencement or continuation of a given
operation. The effect of these risks cannot be accurately
predicted.
Regulation
The oil and gas industry in the United States is subject to
extensive regulation by federal, state and local authorities. At
the federal level, various federal rules, regulations and
procedures apply, including those issued by the United States
Department of Interior, and the United States Department of
Transportation (Office of
14
Pipeline Safety). At the state and local level, various agencies
and commissions regulate drilling, production and midstream
activities. These federal, state and local authorities have
various permitting, licensing and bonding requirements. Various
remedies are available for enforcement of these federal, state
and local rules, regulations and procedures, including fines,
penalties, revocation of permits and licenses, actions affecting
the value of leases, wells or other assets, and suspension of
production. As a result, there can be no assurance that we will
not incur liability for fines and penalties or otherwise subject
us to the various remedies as are available to these federal,
state and local authorities. However, we believe that we are
currently in material compliance with these federal, state and
local rules, regulations and procedures.
Transportation
and Sale of Gas
The Federal Energy Regulatory Commission, or FERC, regulates
interstate gas pipeline transportation rates and service
conditions. Although FERC does not regulate gas producers such
as us, the agencys actions are intended to foster
increased competition within all phases of the gas industry and
its regulation of third-party pipelines and facilities could
indirectly affect our ability to transport or market our
production. To date, FERCs pro-competition policies have
not materially affected our business or operations. It is
unclear what impact, if any, future rules or increased
competition within the gas industry will have on our gas sales
efforts.
FERC or other federal or state regulatory agencies may consider
additional proposals or proceedings that might affect the gas
industry. In addition, new legislation may affect the industries
and markets in which we operate. We cannot predict when or if
these proposals will become effective or any effect they may
have on our operations. We do not believe, however, that any of
these proposals will affect us any differently than other gas
producers with which we compete.
Regulation
of Production
Oil and gas production is regulated under a wide range of
federal and state statutes, rules, orders and regulations. State
and federal statutes and regulations require permits for
drilling operations, drilling bonds and reports concerning
operations. The states in which we own and operate properties
have regulations governing conservation matters, including
provisions for the unitization or pooling of oil and gas
properties, the establishment of maximum rates of production
from oil and gas wells, the regulation of spacing, and
requirements for plugging and abandonment of wells. Also, each
state generally imposes an ad valorem, production or severance
tax with respect to production and sale of oil, gas and gas
liquids within its jurisdiction.
Environmental
Regulations
In the United States, the exploration for and development of oil
and gas and the drilling and operation of wells, fields and
gathering systems are subject to extensive federal, state and
local laws and regulations governing environmental protection as
well as discharge of materials into the environment. Similar
environmental laws exist in Canada. These laws and regulations
may, among other things:
|
|
|
|
|
require the acquisition of various permits before drilling
commences;
|
|
|
|
require the installation of expensive pollution control
equipment;
|
|
|
|
restrict the types, quantities and concentration of various
substances that can be released into the environment in
connection with oil and gas drilling production, transportation
and processing activities;
|
|
|
|
suspend, limit or prohibit construction, drilling and other
activities in certain lands lying within wilderness, wetlands
and other protected areas; and
|
|
|
|
require remedial measures to mitigate and remediate pollution
from historical and ongoing operations, such as the closure of
waste pits and plugging of abandoned wells.
|
These laws, rules and regulations may also restrict the rate of
oil and gas production below the rate that would otherwise be
possible. The regulatory burden on the oil and gas industry
increases the cost of doing business in the industry and
consequently affects profitability.
15
Governmental authorities have the power to enforce compliance
with environmental laws, regulations and permits, and violations
are subject to injunction, as well as administrative, civil and
criminal penalties. The effects of existing and future laws and
regulations could have a material adverse impact on our
business, financial condition and results of operations. While
we believe that we are in substantial compliance with existing
environmental laws and regulations and that continued compliance
with current requirements would not have a material adverse
effect on us, there is no assurance that this will continue in
the future.
The following is a summary of some of the existing laws, rules
and regulations to which our business operations are subject.
Comprehensive
Environmental Response, Compensation and Liability
Act
The Comprehensive Environmental Response, Compensation and
Liability Act of 1980, or CERCLA, also known as the Superfund
law, and comparable state statutes impose strict, and under
certain circumstances, joint and several liability, on classes
of persons who are considered to be responsible for the release
of a hazardous substance into the environment. These persons
include the owner or operator of the site where the release
occurred, and anyone who disposed or arranged for the disposal
of a hazardous substance released at the site. Under CERCLA,
such persons may be subject to strict, joint and several
liabilities for the costs of cleaning up the hazardous
substances that have been released into the environment, for
damages to natural resources and for the costs of certain health
studies. In addition, it is not uncommon for neighboring
landowners and other third-parties to file claims for personal
injury and property damage allegedly caused by the hazardous
substances released into the environment. While we generate
materials in the course of our operations that may be regulated
as hazardous substances, we have not received notification that
we may be potentially responsible for cleanup costs under CERCLA.
Waste
Handling
The Resource Conservation and Recovery Act, or RCRA, and
comparable state statutes, regulate the generation,
transportation, treatment, storage, disposal and cleanup of
hazardous and non-hazardous wastes. Under the auspices of the
federal Environmental Protection Agency, or EPA, the individual
states administer some or all of the provisions of RCRA,
sometimes in conjunction with their own, more stringent
requirements. Drilling fluids, produced waters and most of the
other wastes associated with the exploration, development,
exploitation and production of oil or gas are currently
regulated under RCRAs non-hazardous waste provisions.
However, it is possible that certain oil and gas exploration and
production wastes now classified as non-hazardous could be
classified as hazardous wastes in the future. Any such change
could result in an increase in our operating expenses, which
could have a material adverse effect on our business, financial
condition and results of operations.
We currently own or lease, and have in the past owned or leased,
properties that for many years have been used for oil and gas
exploration, production and development activities. Although we
used operating and disposal practices that were standard in the
industry at the time, petroleum hydrocarbons or wastes may have
been disposed of or released on, under or from the properties
owned or leased by us or on, under or from other locations where
such wastes have been taken for disposal. In addition, some of
these properties have been operated by third parties whose
treatment and disposal or release of petroleum hydrocarbons and
wastes was not under our control. These properties and the
materials disposed or released on, at, under or from them may be
subject to CERCLA, RCRA and analogous state laws. Under such
laws, we could be required to remove or remediate previously
disposed wastes or contamination, or to perform remedial
activities to prevent future contamination.
Air
Emissions
The federal Clean Air Act and comparable state laws regulate
emissions of various air pollutants through air emissions
permitting programs and the imposition of other requirements. In
addition, the EPA has developed, and continues to develop,
stringent regulations governing emissions of hazardous and toxic
air pollutants at specified sources. These regulatory programs
may require us to obtain permits before
16
commencing construction on a new source of air emissions and may
require us to reduce emissions at existing facilities. As a
result, we may be required to incur increased capital and
operating costs. Additionally, 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 analogous state laws and regulations.
In February 2005, the Kyoto Protocol to the United Nations
Framework Convention on Climate Change, which we refer to as the
Protocol, entered into force. Pursuant to the Protocol, adopting
countries are required to implement national programs to reduce
emissions of certain gases, generally referred to as greenhouse
gases, which are suspected of contributing to global warming.
The United States is not currently a participant in the
Protocol. However, Congress has enacted legislation directed at
reducing greenhouse gas emissions and the EPA may be required to
regulate greenhouse gas emissions, and many states have already
adopted legislation or undertaken regulatory initiatives
addressing greenhouse gas emissions from various sources. The
oil and gas exploration and production industry is a direct
source of certain greenhouse gas emissions, namely carbon
dioxide and methane, and future restrictions on such emissions
would likely adversely impact our future operations, results of
operations and financial condition. At this time, although it is
not possible to accurately estimate how potential future laws or
regulations addressing greenhouse gas emissions would impact our
business, passage of such laws or regulation affecting areas in
which we conduct business could have an adverse effect on our
operations.
Water
Discharges
The Federal Water Pollution Control Act, also known as the Clean
Water Act, and analogous state laws, impose restrictions and
strict controls with respect to the discharge of pollutants,
including spills and leaks of oil and other substances into
regulated waters, including wetlands. The discharge of
pollutants into regulated waters is prohibited, except in
accordance with the terms of a permit issued by the EPA or an
analogous state agency. Federal and state regulatory agencies
can impose administrative, civil and criminal penalties for
non-compliance with discharge permits or other requirements of
the Clean Water Act and analogous state laws and regulations.
OSHA
and Other Laws and Regulations
We are subject to the requirements of the federal Occupational
Safety and Health Act, or OSHA, and comparable state statutes.
The OSHA hazard communication standard, the EPA community
right-to-know
regulations under the Title III of CERCLA and similar state
statutes require that we organize
and/or
disclose information about hazardous materials used or produced
in our operations. We believe that we are in substantial
compliance with these applicable requirements and with other
OSHA and comparable requirements.
We believe that we are in substantial compliance with all
existing environmental laws and regulations that apply to our
current operations and that our ongoing compliance with existing
requirements will not have a material adverse effect on our
financial condition or results of operations. We did not incur
any material capital expenditures for remediation or pollution
control activities for the year ended December 31, 2009. In
addition, as of the date of this annual report, we are not aware
of any environmental issues or claims that will require material
capital expenditures during 2010. However, the passage of more
stringent laws or regulations in the future could have a
negative effect on our business, financial condition and results
of operations, including our ability to develop our undeveloped
acreage. For example, see our discussion of current regulatory
proceedings in New Mexico below.
New
Mexico
In April 2008, the Board of County Commissioners of Rio Arriba
County, New Mexico, or the County, imposed a moratorium on all
oil and gas drilling on private lands the County, pending the
adoption of an ordinance that would regulate oil and gas
operations. The moratorium covered all of our El Vado East
prospect in the County. In May 2009, the Board of County
Commissioners lifted the moratorium and adopted a final oil and
gas drilling ordinance. The ordinance requires special use
permits for oil and gas operations in the eastern part of the
County where our El Vado East prospect is located.
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Our mineral lease for El Vado East currently requires us to
drill a minimum of eight wells before the end of the primary
term of the lease, which originally was set to expire on
April 2, 2009. However, the drilling moratorium, regulatory
proceedings and an inability to obtain permits delayed our
drilling plans in El Vado East and, accordingly, we have invoked
our right to assert force majeure under our mineral
lease and extended the primary term of the lease during the
period of force majeure, up to a maximum of four years past the
original primary term, or April 2, 2013.
In November 2009, the New Mexico Oil Conservation Division
conditionally approved our applications for permits to drill for
11 locations in El Vado East. In December 2009, the
Countys Planning & Zoning Commission
conditionally approved our applications for special use permits
for five drilling locations in El Vado East. We have filed
applications for special use permits with the County for a total
of eight drilling locations. These applications are subject to
final approval of the Countys Board of County
Commissioners.
Assuming no further, unexpected delays in the permitting
process, we believe we will be able to satisfy our initial
drilling commitment before the end of the primary term as
extended by force majeure. However, our inability to timely meet
this drilling commitment or negotiate appropriate extensions
under the lease could result in the termination of the lease and
write-off of our investment in El Vado East, the current
carrying value of which is $2.9 million.
Employees
At February 28, 2010, we had 45 full-time employees,
19 of whom are field personnel. We regularly use independent
contractors and consultants to perform various field and other
services. None of our employees are represented by a labor union
or covered by any collective bargaining agreement. We believe
that our relations with our employees are excellent.
Insurance
Matters
As is common in the oil and gas industry, we will not insure
fully against all risks associated with our business either
because such insurance is not available or because premium costs
are considered prohibitive. A loss not fully covered by
insurance could have a material adverse effect on our business,
financial condition and results of operations.
Available
Information
We maintain an internet website under the name
www.approachresources.com. The information on our website
is not a part of this report. We make available, free of charge,
on our website, the annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and amendments to those reports, as soon as reasonably
practicable after providing such reports to the SEC. Also, the
charters of our Audit Committee and Compensation and Nominating
Committee, and our Code of Conduct, are available on our website
and in print to any stockholder who provides a written request
to the Corporate Secretary at One Ridgmar Centre, 6500 West
Freeway, Suite 800, Fort Worth, Texas 76116.
We file annual reports on
Form 10-K,
quarterly reports on
Form 10-Q
and current reports on
Form 8-K,
proxy statements and other documents with the SEC under the
Exchange Act. The public may read and copy any materials that we
file with the SEC at the SECs Public Reference Room at
100 F Street, NE, Washington DC 20549. The public may
obtain information on the operation of the Public Reference Room
by calling the SEC at
1-800-SEC-0330.
Also, the SEC maintains an internet website that contains
reports, proxy and information statements, and other information
regarding issuers, including Approach, that file electronically
with the SEC. The public can obtain any document we file with
the SEC at www.sec.gov. Information contained on or
connected to our website is not incorporated by reference into
this
Form 10-K
and should not be considered part of this report or any other
filing that we make with the SEC.
18
You should carefully consider the risk factors set forth below
as well as the other information contained in this report before
investing in our common stock. Any of the following risks could
materially and adversely affect our business, financial
condition or results of operations. In such a case, you may lose
all or part of your investment. The risks described below are
not the only risks facing us. Additional risks and uncertainties
not currently known to us or those we currently view to be
immaterial may also materially adversely affect our business,
financial condition or results of operations.
Risks
Related to the Oil and Natural Gas Industry and Our
Business
Oil
and gas prices are volatile, and a decline in oil or gas prices
could significantly affect our business, financial condition or
results of operations and our ability to meet our capital
expenditure requirements and financial
commitments.
Our revenues, profitability and cash flow depend substantially
upon the prices and demand for oil and gas. The markets for
these commodities are volatile, and even relatively modest drops
in prices can affect significantly our financial results and
impede our growth. Prices for oil and gas fluctuate widely in
response to relatively minor changes in the supply and demand
for oil and gas, market uncertainty and a variety of additional
factors beyond our control, such as:
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the level of domestic and foreign consumer demand for oil and
gas;
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domestic and foreign supply of oil and gas, including LNG;
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overall United States and global economic conditions;
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price and availability of alternative fuels;
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price and quantity of foreign imports;
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commodity processing, gathering and transportation availability
and the availability of refining capacity;
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domestic and foreign governmental regulations;
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political conditions in or affecting other gas producing and oil
producing countries;
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the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls;
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weather conditions, including unseasonably warm winter weather
and tropical storms; and
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technological advances affecting oil and gas consumption.
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Further, oil prices and gas prices do not necessarily fluctuate
in direct relationship to each other. Because more than 77% of
our estimated proved reserves as of December 31, 2009 were
gas reserves, our financial results are more sensitive to
movements in gas prices. Recent gas prices have been extremely
volatile and we expect this volatility to continue. For example,
from January 1, 2009 to December 31, 2009, the NYMEX
gas spot price ranged from a high of $6.07 per MMBtu to a low of
$2.51 per MMBtu.
The results of higher investment in the exploration for and
production of oil and gas and other factors, such as global
economic and financial conditions discussed below, may cause the
price of gas to fall. Lower oil and gas prices may not only
cause our revenues to decrease but also may reduce the amount of
oil and gas that we can produce economically. Substantial
decreases in oil and gas prices would render uneconomic some or
all of our drilling locations. This may result in our having to
make substantial downward adjustments to our estimated proved
reserves and could have a material adverse effect on our
business, financial condition and results of operations.
Further, if oil and gas prices significantly decline for an
extended period of time, we may, among other things, be unable
to maintain or increase our borrowing capacity, repay current or
future debt or obtain additional capital on attractive terms,
all of which can affect the value of our common stock.
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Changes
in the differential between NYMEX or other benchmark prices of
oil and gas and the reference or regional index price used to
price our actual oil and gas sales could have a material adverse
effect on our financial condition or results of
operations.
The reference or regional index prices that we use to price our
oil and gas sales sometimes reflect a discount to the relevant
benchmark prices, such as NYMEX. The difference between the
benchmark price and the price we reference in our sales
contracts is called a differential. We cannot accurately predict
oil and gas differentials. Changes in differentials between the
benchmark price for oil and gas and the reference or regional
index price we reference in our sales contracts could have a
material adverse effect on our results of operations and
financial condition.
Future
economic conditions in the U.S. and international markets could
materially and adversely affect our business, financial
condition or results of operations.
The U.S. and other world economies continue to experience
the effects of a global recession and credit market crisis. More
volatility may occur before a sustainable growth rate is
achieved either domestically or globally. Even if such growth
rate is achieved, such a rate may be lower than the
U.S. and international economies have experienced in the
past. Global economic growth drives demand for energy from all
sources, including fossil fuels. A lower, future economic growth
rate will result in decreased demand for our oil and gas
production and lower commodity prices, which will reduce our
cash flows from operations and our profitability.
Difficult
conditions in the credit and capital markets may limit our
ability to obtain funding under our current revolving credit
facility or other sources of debt or equity financing. The
inability to obtain funding could prevent us from meeting our
future capital needs to fund our development
program.
Credit and capital markets have experienced unprecedented
volatility and disruption. Although markets began to recover in
2009, they may remain volatile and unpredictable, particularly
if weaker than expected economic growth persists. We have a
significant inventory of development properties that will
require substantial future investment. We will need financing to
fund these and other activities. Our future access to capital
could be limited if the credit or broader capital markets are
constrained. This could prevent or significantly delay
development of our assets.
Our
lenders can limit our borrowing capabilities, which may
materially impact our operations.
At December 31, 2009, we had approximately
$32.3 million of outstanding debt under our revolving
credit facility, and our borrowing base was $115 million.
The borrowing base limitation under our credit facility is
semi-annually redetermined based upon a number of factors,
including commodity prices and reserve levels. In addition to
such semi-annual redeterminations, our lenders may request one
additional redetermination during any
12-month
period. Upon a redetermination, our borrowing base could be
substantially reduced, and if the amount outstanding under our
credit facility at any time exceeds the borrowing base at such
time, we may be required to repay a portion of our outstanding
borrowings. We use cash flow from operations and bank borrowings
to fund our exploration and development activities. A reduction
in our borrowing base could limit those activities. In addition,
we may significantly change our capital structure to make future
acquisitions or develop our properties. Changes in capital
structure may significantly increase our debt. If we incur
additional debt for these or other purposes, the related risks
that we now face could intensify. A higher level of debt also
increases the risk that we may default on our debt obligations.
Our ability to meet our debt obligations and to reduce our level
of debt depends on our future performance, which is affected by
general economic conditions and financial, business and other
factors, many of which are beyond our control.
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Drilling
and exploring for, and producing, oil and gas are high risk
activities with many uncertainties that could adversely affect
our business, financial condition or results of
operations.
Drilling and exploration are the main methods we use to replace
our reserves. However, drilling and exploration operations may
not result in any increases in reserves for various reasons.
Exploration activities involve numerous risks, including the
risk that no commercially productive oil or gas reservoirs will
be discovered. In addition, the future cost and timing of
drilling, completing and producing wells is often uncertain.
Furthermore, drilling operations may be curtailed, delayed or
canceled as a result of a variety of factors, including:
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reductions in oil and gas prices;
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limitations in the market for oil and gas;
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inadequate capital resources;
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unavailability or high cost of drilling rigs, equipment or labor;
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compliance with governmental regulations;
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unexpected drilling conditions, pressure or irregularities in
formations, equipment failures or accidents;
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lack of acceptable prospective acreage;
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adverse weather conditions;
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surface access restrictions;
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title problems; and
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mechanical difficulties.
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The
use of geophysical and geological analyses and other technical
or operating data to evaluate drilling prospects is uncertain
and does not guarantee drilling success or recovery of
economically producible reserves.
Our decisions to explore, develop and acquire prospects or
properties depend in part on data obtained through geophysical
and geological analyses, production data and engineering
studies, the results of which are often uncertain. Even when
used and properly interpreted,
3-D seismic
data and visualization techniques only assist geoscientists and
geologists in identifying subsurface structures and hydrocarbon
indicators. They do not allow the interpreter to know
conclusively if hydrocarbons are present or producible
economically. In addition, the use of
3-D seismic
and other advanced technologies require greater pre-drilling
expenditures than traditional drilling strategies.
Currently,
all of our producing properties are located in three counties in
Texas, making us vulnerable to risks associated with having our
production concentrated in a small area.
All of our producing properties and estimated proved reserves
are geographically concentrated in three counties in Texas,
Crockett, Schleicher and Limestone. Our current production is
primarily attributable to three fields in Crockett and
Schleicher Counties, Ozona Northeast and the Angus and Holt
fields in Cinco Terry. As a result of this concentration, we are
disproportionately exposed to the natural decline of production
from these fields, and particularly Ozona Northeast, as well as
the impact of delays or interruptions of production from these
wells caused by significant governmental regulation,
transportation capacity constraints, curtailments of production,
natural disasters, interruption of transportation of gas
produced from the wells in these fields or other events that
impact these areas.
21
Identified
drilling locations that we decide to drill may not yield oil or
gas in commercially viable quantities and are susceptible to
uncertainties that could materially alter the occurrence or
timing of their drilling.
Our drilling locations are in various stages of evaluation,
ranging from locations that are ready to be drilled to locations
that will require substantial additional evaluation and
interpretation. There is no way to predict before drilling and
testing whether any particular drilling location will yield oil
or gas in sufficient quantities to recover drilling or
completion costs or to be economically viable. The use of
seismic data and other technologies and the study of producing
fields in the same area will not enable us to know conclusively
before drilling whether oil or gas will be present or, if
present, whether oil or gas will be present in commercial
quantities. The analysis that we perform may not be useful in
predicting the characteristics and potential reserves associated
with our drilling locations. As a result, we may not find
commercially viable quantities of oil and gas.
Our drilling locations represent a significant part of our
growth strategy. Our ability to drill and develop these
locations depends on a number of factors, including oil and gas
prices, costs, the availability of capital, seasonal conditions,
regulatory approvals and drilling results. Because of these
uncertainties, we do not know when the drilling locations we
have identified will be drilled or if they will ever be drilled
or if we will be able to produce oil or gas from these or any
proved drilling locations. As such, our actual drilling
activities may be materially different from those presently
identified, which could adversely affect our business, results
of operations or financial condition.
Unless
we replace our oil and gas reserves, our reserves and production
will decline.
Our future oil and gas production depends on our success in
finding or acquiring additional reserves. If we fail to replace
reserves through drilling or acquisitions, our level of
production and cash flows will be adversely affected. In
general, production from oil and gas properties declines as
reserves are depleted, with the rate of decline depending on
reservoir characteristics. Our total proved reserves will
decline as reserves are produced unless we conduct other
successful exploration and development activities or acquire
properties containing proved reserves, or both. Our ability to
make the necessary capital investment to maintain or expand our
asset base of oil and gas reserves would be impaired to the
extent cash flow from operations is reduced and external sources
of capital become limited or unavailable. We may not be
successful in exploring for, developing or acquiring additional
reserves.
Our
actual production, revenues and expenditures related to our
reserves are likely to differ from our estimates of our proved
reserves. We may experience production that is less than
estimated and drilling costs that are greater than estimated in
our reserve reports. These differences may be
material.
The proved oil and gas reserve information included in this
report represents estimates. Petroleum engineering is a
subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and
of future net cash flows necessarily depend upon a number of
variable factors and assumptions, including:
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historical production from the area compared with production
from other similar producing areas;
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the assumed effects of regulations by governmental agencies;
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assumptions concerning future oil and gas prices; and
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assumptions concerning future operating costs, severance and
excise taxes, development costs and workover and remedial costs.
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Because all reserve estimates are to some degree subjective,
each of the following items may differ materially from those
assumed in estimating proved reserves:
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the quantities of oil and gas that are ultimately recovered;
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the production and operating costs incurred;
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the amount and timing of future development
expenditures; and
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future oil and gas prices.
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As of December 31, 2009, approximately 57% of our proved
reserves were proved undeveloped. Estimates of proved
undeveloped reserves are even less reliable than estimates of
proved developed reserves.
Furthermore, different reserve engineers may make different
estimates of reserves and future net revenues based on the same
available data. Our actual production, revenues and expenditures
with respect to reserves will likely be different from estimates
and the differences may be material. The
PV-10
included in this report should not be considered as the current
market value of the estimated oil and gas reserves attributable
to our properties.
PV-10 is
based on the unweighted, arithmetic average of the closing price
on the first day of the month for the
12-month
period prior to fiscal year end, while actual future prices and
costs may be materially higher or lower. If natural gas, oil and
NGL prices decline by 10% from the Current Price Case ($3.87 per
MMBtu, $61.04 per Bbl of oil and $27.20 per Bbl of NGLs to $3.48
per MMBtu, $54.94 per Bbl of oil and $24.48 per Bbl of NGLs),
then our
PV-10 as of
December 31, 2009, would decrease from $128.9 million
to $86.4 million. The average market price received for our
production for the month of December 31, 2009 was $5.84 per
Mcf (after basis and Btu adjustments), $70.61 per Bbl of oil and
$43.12 per Bbl of NGLs.
Actual future net revenues also will be affected by factors such
as:
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the amount and timing of actual production;
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supply and demand for oil and gas;
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increases or decreases in consumption; and
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changes in governmental regulations or taxation.
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The
unavailability or high cost of drilling rigs, equipment,
supplies, personnel and oilfield services could adversely affect
our ability to execute our exploration and development plans on
a timely basis and within our budget.
Our industry is cyclical and, from time to time, there is a
shortage of drilling rigs, equipment, supplies or qualified
personnel. During these periods, the costs and delivery times of
rigs, equipment and supplies are substantially greater. In
addition, the demand for, and wage rates of, qualified drilling
rig crews rise as the number of active rigs in service
increases. Increasing levels of exploration and production will
increase the demand for oilfield services, and the costs of
these services may increase, while the quality of these services
may suffer. We currently are experiencing increased demand for
drilling rigs, crews and certain oilfield services in the
Permian Basin, our primary area of operation. If the
unavailability or high cost of drilling rigs, equipment,
supplies or qualified personnel becomes particularly severe in
the Permian Basin, we could be materially and adversely affected
because our operations and properties are concentrated in the
Permian Basin.
We
have leases and options for undeveloped acreage that may expire
in the near future.
As of December 31, 2009, we held mineral leases or options
in each of our areas of operations that are still within their
original lease term and are not currently held by production.
Unless we establish commercial production on the properties
subject to these leases, most of these leases will expire
between 2010 and 2015. If these leases or options expire, we
will lose our right to develop the related properties. See
Items 1. and 2. Business and Properties
Undeveloped Acreage Expirations for a table summarizing
the expiration schedule of our undeveloped acreage over the next
three years.
Competition
in the oil and gas industry is intense, and many of our
competitors have resources that are greater than
ours.
We operate in a highly competitive environment for acquiring
prospects and productive properties, marketing oil and gas and
securing equipment and trained personnel. Many of our
competitors are major and large independent oil and gas
companies that possess and employ financial, technical and
personnel resources
23
substantially greater than ours. Those companies may be able to
develop and acquire more prospects and productive properties
than our financial or personnel resources permit. Our ability to
acquire additional prospects and discover reserves in the future
will depend on our ability to evaluate and select suitable
properties and consummate transactions in a highly competitive
environment. Also, there is substantial competition for capital
available for investment in the oil and gas industry. Larger
competitors may be better able to withstand sustained periods of
unsuccessful drilling and absorb the burden of changes in laws
and regulations more easily than we can, which would adversely
affect our competitive position. We may not be able to compete
successfully in the future in acquiring prospective reserves,
developing reserves, marketing hydrocarbons, attracting and
retaining quality personnel and raising additional capital.
Our
customer base is concentrated, and the loss of our key customers
could, therefore, adversely affect our financial
results.
In 2009, Ozona Pipeline, WTG Benedum/Belvan Partners, LP and
Shell accounted for approximately 43.3%, 26.1% and 22.4%,
respectively, of our total oil and gas sales excluding realized
commodity derivative settlements. To the extent that Ozona
Pipeline, WTG Benedum/Belvan Partners or Shell reduces their
purchases in gas or oil or defaults on their obligations to us,
we would be adversely affected unless we were able to make
comparably favorable arrangements with other customers. These
purchasers default or non-performance could be caused by
factors beyond our control. A default could occur as a result of
circumstances relating directly to one or both of these
customers, or due to circumstances related to other market
participants with which the customer has a direct or indirect
relationship.
We
depend on our management team and other key personnel.
Accordingly, the loss of any of these individuals could
adversely affect our business, financial condition and the
results of operations and future growth.
Our success largely depends on the skills, experience and
efforts of our management team and other key personnel. The loss
of the services of one or more members of our senior management
team or of our other employees with critical skills needed to
operate our business could have a negative effect on our
business, financial condition, results of operations and future
growth. We have entered into employment agreements with J. Ross
Craft, our President and Chief Executive Officer and Steven P.
Smart, our Executive Vice President and Chief Financial Officer.
If either of these officers or other key personnel resign or
become unable to continue in their present roles and are not
adequately replaced, our business operations could be materially
adversely affected. Our ability to manage our growth, if any,
will require us to continue to train, motivate and manage our
employees and to attract, motivate and retain additional
qualified personnel. Competition for these types of personnel is
intense, and we may not be successful in attracting,
assimilating and retaining the personnel required to grow and
operate our business profitably.
We
have three affiliated stockholders who, together with our board
and management, have a 42% interest in our company, whose
interests may differ from your interests and who will be able to
control or substantially influence the outcome of matters voted
upon by our stockholders.
At December 31, 2009, Yorktown Energy Partners V,
L.P., Yorktown Energy Partners VI, L.P. and Yorktown Energy
Partners VII, L.P., or collectively, Yorktown, which are under
common management, beneficially owned approximately 32% of our
outstanding common stock in the aggregate, together with a
Yorktown representative who serves on our board of directors. In
addition, our non-Yorktown directors and management team
beneficially own or control approximately 10% of our common
stock outstanding. As a result of this ownership and control,
Yorktown, together with our board and management, has the
ability to control or substantially influence the vote in any
election of directors. Yorktown, together with our board and
management, also has control or substantial influence over our
decisions to enter into significant corporate transactions and,
in their capacity as our majority stockholders, these
stockholders may have the ability to effectively block any
transactions that they do not believe are in Yorktowns or
managements best interest. As
24
a result, Yorktown, together with our board and management, is
able to control, directly or indirectly and subject to
applicable law, or substantially influence all matters affecting
us, including the following:
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any determination with respect to our business direction and
policies, including the appointment and removal of officers;
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any determinations with respect to mergers, business
combinations or dispositions of assets;
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our capital structure;
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compensation, option programs and other human resources policy
decisions;
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changes to other agreements that may adversely affect
us; and
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the payment, or nonpayment, of dividends on our common stock.
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Yorktown, together with our board and management, also may have
an interest in pursuing transactions that, in their judgment,
enhance the value of their respective equity investments in our
company, even though those transactions may involve risks to you
as a minority stockholder. In addition, circumstances could
arise under which their interests could be in conflict with the
interests of our other stockholders or you, a minority
stockholder. Also, Yorktown and their affiliates have and may in
the future make significant investments in other companies, some
of which may be competitors. Yorktown and its affiliates are not
obligated to advise us of any investment or business
opportunities of which they are aware, and they are not
restricted or prohibited from competing with us.
We
have renounced any interest in specified business opportunities,
and certain members of our board of directors and certain of our
stockholders generally have no obligation to offer us those
opportunities.
In accordance with Delaware law, we have renounced any interest
or expectancy in any business opportunity, transaction or other
matter in which our outside directors and certain of our
stockholders, each referred to as a Designated Party,
participates or desires to participate in that involves any
aspect of the exploration and production business in the oil and
industry. If any such business opportunity is presented to a
Designated Person who also serves as a member of our board of
directors, the Designated Party has no obligation to communicate
or offer that opportunity to us, and the Designated Party may
pursue the opportunity as he sees fit, unless:
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it was presented to the Designated Party solely in that
persons capacity as a director of our company and with
respect to which, at the time of such presentment, no other
Designated Party has independently received notice of or
otherwise identified the business opportunity; or
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the opportunity was identified by the Designated Party solely
through the disclosure of information by or on behalf of us.
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As a result of this renunciation, our outside directors should
not be deemed to be breaching any fiduciary duty to us if they
or their affiliates or associates pursue opportunities as
described above and our future competitive position and growth
potential could be adversely affected.
We are
subject to complex governmental laws and regulations that may
adversely affect the cost, manner or feasibility of doing
business.
Our operations and facilities are subject to extensive federal,
state and local laws and regulations relating to the exploration
for, and the development, production and transportation of, oil
and gas, and operating safety, and protection of the
environment, including those relating to air emissions,
wastewater discharges, land use, storage and disposal of wastes
and remediation of contaminated soil and groundwater. Future
laws or regulations, any adverse changes in the interpretation
of existing laws and regulations or our failure to comply with
existing legal requirements may harm our business, results of
operations and financial condition. We may
25
encounter reductions in reserves or be required to make large
and unanticipated capital expenditures to comply with
governmental laws and regulations, such as:
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price control;
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taxation;
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lease permit restrictions;
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drilling bonds and other financial responsibility requirements,
such as plug and abandonment bonds;
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spacing of wells;
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unitization and pooling of properties;
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safety precautions; and
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permitting requirements.
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Under these laws and regulations, we could be liable for:
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personal injuries;
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property and natural resource damages;
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well reclamation costs, soil and groundwater remediation
costs; and
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governmental sanctions, such as fines and penalties.
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Our operations could be significantly delayed or curtailed, and
our cost of operations could significantly increase as a result
of environmental safety and other regulatory requirements or
restrictions. We are unable to predict the ultimate cost of
compliance with these requirements or their effect on our
operations. We may be unable to obtain all necessary licenses,
permits, approvals and certificates for proposed projects.
Intricate and changing environmental and other regulatory
requirements may require substantial expenditures to obtain and
maintain permits. If a project is unable to function as planned,
for example, due to costly or changing requirements or local
opposition, it may create expensive delays, extended periods of
non-operation or significant loss of value in a project. See
Items 1. and 2., Business and Properties
Regulation.
Possible
regulation related to global warming and climate change could
have an adverse effect on our business, financial condition or
results of operations and demand for natural gas and
oil.
In June 2009, the United States House of Representatives passed
the American Clean Energy and Security Act of 2009, also known
as the Waxman-Markey Bill or ACESA. Further, on November 5,
2009, the United States Senate passed out of committee the Clean
Energy Jobs and American Power Act, also known as the
Boxer-Kerry Bill. These bills contain provisions that would
establish a cap and trade system for restricting greenhouse gas
emissions in the United States. Methane, a primary component of
natural gas, and carbon dioxide, a byproduct of the burning of
oil, natural gas and refined petroleum products, are considered
greenhouse gases. Under such a system, certain sources of
greenhouse gas emissions would be required to obtain greenhouse
gas emission allowances corresponding to their
annual emissions of greenhouse gases. The number of emission
allowances issued each year would decline as necessary to meet
overall emission reduction goals. As the number of greenhouse
gas emission allowances declines each year, the cost or value of
allowances is expected to escalate significantly. The ultimate
outcome of this federal legislative initiative remains uncertain.
In addition to pending climate legislation, the Environmental
Protection Agency, or EPA, has issued greenhouse gas monitoring
and reporting regulations that went into effect January 1,
2010, and require reporting by regulated facilities by March
2011 and annually thereafter. Beyond measuring and reporting,
the EPA issued an Endangerment Finding under
section 202(a) of the Clean Air Act, concluding greenhouse
gas pollution threatens the public health and welfare of current
and future generations. The finding could lead to regulations
that would require permits for and reductions in greenhouse gas
emissions for certain facilities. EPA has proposed such
greenhouse gas regulations and may issue final rules this year.
26
In the courts, several decisions have been issued that could
increase the risk of claims being filed by governments and
private parties against companies that have significant
greenhouse gas emissions. Such cases may seek to challenge air
emissions permits that greenhouse gas emitters apply for and
seek to force emitters to reduce their emissions or seek damages
for alleged climate change impacts to the environment, people
and property.
Any laws or regulations that may be adopted to restrict or
reduce emissions of greenhouse gases could require us to incur
increased operating and compliance costs, and could have an
adverse effect on demand for the oil and natural gas that we
produce.
Legislation
and regulatory initiatives relating to hydraulic fracturing
could result in increased costs, additional operating
restrictions or delays or lower returns on our capital
investments.
Congress currently is considering legislation to amend the
federal Safe Drinking Water Act to require the disclosure of
chemicals used by the oil and gas industry in the hydraulic
fracturing, or fracing, process. Hydraulic
fracturing involves the injection of water, sand and chemicals
under pressure into rock formations to stimulate oil and natural
gas production. We engage third parties to provide hydraulic
fracturing or other well stimulation services to us for many of
the wells that we drill and operate. Supporters of legislation
currently pending before the Senate and House of Representatives
have asserted that chemicals used in the fracturing process may
adversely impact drinking water. The proposed legislation could
lead to (i) additional legal challenges to the fracing
process based on alleged impact to drinking water or
(ii) restrictions on the fluids that can be used in the
process. Additional regulation and legal challenges could lead
to operational delays and increased compliance and operating
costs. Restrictions on fluids used in the fracing process could
negatively impact the productivity of our future drilling
locations, lower our return on capital expenditures and have a
material adverse effect on our business, financial condition,
results of operations and quantities of oil and gas reserves
that may be economically produced.
Changes
in tax laws may adversely affect our results of operations and
cash flows.
President Obamas Proposed Fiscal Year 2011 Budget includes
proposed legislation that would, if enacted into law, make
significant changes to U.S. tax laws, including the
elimination of certain key United States federal income tax
incentives currently available to oil and natural gas
exploration and production companies. These changes include, but
are not limited to:
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the repeal of the percentage depletion allowance for oil and
natural gas properties;
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the elimination of current deductions for intangible drilling
costs;
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the elimination of the deduction for certain domestic production
activities; and
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an extension of the amortization period for certain geological
and geophysical expenditures.
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It is unclear whether any such changes will be enacted or how
soon any such changes could become effective. The passage of any
legislation as a result of these proposals or any other similar
changes in U.S. federal income tax laws could eliminate or
otherwise limit certain tax deductions that are currently
available with respect to oil and natural gas exploration and
development, and any such change could negatively impact our
financial condition and results of operations.
Derivatives
regulation could restrict our ability to execute commodity
derivative transactions to protect against risk associated with
fluctuating commodity prices.
Various measures are being proposed by committees of Congress,
the U.S. Treasury Department, and other agencies to
restrict the use of
over-the-counter,
or OTC, derivative instruments. These proposals include, but are
not limited to, requiring cash collateral on all OTC derivatives
and requiring all OTC derivatives to be executed and settled
through an exchange system. Although we do not currently know
the exact form any final legislation or rule-making activity
will take, any restriction on the use of OTC instruments could
have a significant impact on our business. Limits on the use of
OTC instruments could significantly reduce our ability
27
to execute strategic commodity derivatives transactions to
reduce price uncertainty and to protect cash flows. In addition,
cash collateral requirements could create significant burdens on
our liquidity and exchange system trades may restrict our
ability to execute derivative instruments to fit our strategic
needs.
Operating
hazards, natural disasters or other interruptions of our
operations could result in potential liabilities, which may not
be fully covered by our insurance.
The oil and gas business involves certain operating hazards such
as:
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well blowouts;
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cratering;
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explosions;
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uncontrollable flows of gas, oil or well fluids;
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fires;
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pollution; and
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releases of toxic gas.
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The occurrence of one of the above may result in injury, loss of
life, suspension of operations, environmental damage and
remediation
and/or
governmental investigations and penalties.
In addition, our operations in Texas are especially susceptible
to damage from natural disasters such as tornados and involve
increased risks of personal injury, property damage and
marketing interruptions. Any of these operating hazards could
cause serious injuries, fatalities or property damage, which
could expose us to liabilities. The payment of any of these
liabilities could reduce, or even eliminate, the funds available
for exploration, development, exploitation and acquisition, or
could result in a loss of our properties. Consistent with
insurance coverage generally available to the industry, our
insurance policies provide limited coverage for losses or
liabilities relating to pollution, with broader coverage for
sudden and accidental occurrences. Our insurance might be
inadequate to cover our liabilities. The insurance market in
general and the energy insurance market in particular have been
difficult markets over the past several years. Insurance costs
are expected to continue to increase over the next few years and
we may decrease coverage and retain more risk to mitigate future
cost increases. If we incur substantial liability and the
damages are not covered by insurance or are in excess of policy
limits, or if we incur liability at a time when we are not able
to obtain liability insurance, then our business, results of
operations and financial condition could be materially adversely
affected.
Our
results are subject to quarterly and seasonal
fluctuations.
Our quarterly operating results have fluctuated in the past and
could be negatively impacted in the future as a result of a
number of factors, including:
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seasonal variations in oil and gas prices;
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variations in levels of production; and
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the completion of exploration and production projects.
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Market
conditions or transportation impediments may hinder our access
to oil and gas markets or delay our production.
Market conditions and the unavailability of satisfactory oil and
gas processing and transportation may hinder our access to oil
and gas markets or delay our production. Although currently we
control the gathering system operations for a majority of our
production in Ozona Northeast, we do not have such control over
the regional or downstream pipelines in Ozona Northeast or in
other areas where we operate or expect to conduct operations.
The availability of a ready market for our oil and gas
production depends on a number of factors,
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including the demand for and supply of oil and gas and the
proximity of reserves to pipelines or trucking and terminal
facilities. In addition, the amount of oil and gas that can be
produced and sold is subject to curtailment in certain
circumstances, such as pipeline interruptions due to scheduled
and unscheduled maintenance, excessive pressure, ability of
downstream processing facilities to accept unprocessed gas,
physical damage to the gathering or transportation system or
lack of contracted capacity on such systems. The curtailments
arising from these and similar circumstances may last from a few
days to several months, and in many cases we are provided with
limited, if any, notice as to when these circumstances will
arise and their duration. As a result, we may not be able to
sell, or may have to transport by more expensive means, the oil
and gas production from wells or we may be required to shut in
gas wells or delay initial production until the necessary
gathering and transportation systems are available. Any
significant curtailment in gathering system or pipeline
capacity, or significant delay in construction of necessary
gathering and transportation facilities, could adversely affect
our business, financial condition or results of operations.
Environmental
liabilities may expose us to significant costs and
liabilities.
There is inherent risk of incurring significant environmental
costs and liabilities in our oil and gas operations due to the
handling of petroleum hydrocarbons and generated wastes, the
occurrence of air emissions and water discharges from
work-related activities and the legacy of pollution from
historical industry operations and waste disposal practices. We
may incur joint and several or strict liability under these
environmental laws and regulations in connection with spills,
leaks or releases of petroleum hydrocarbons and wastes on, under
or from our properties and facilities, many of which have been
used for exploration, production or development activities for
many years, oftentimes by third parties not under our control.
Private parties, including the owners of properties upon which
we conduct drilling and production activities as well as
facilities where our petroleum hydrocarbons or wastes are taken
for reclamation or disposal, may also have the right to pursue
legal actions to enforce compliance as well as to seek damages
for non-compliance with environmental laws and regulations or
for personal injury or property damage. In addition, changes in
environmental laws and regulations occur frequently, and any
such changes that result in more stringent and costly waste
handling, storage, transport, disposal or remediation
requirements could have a material adverse effect on our
business, financial condition and results of operations. We may
not be able to recover some or any of these costs from
insurance. See Items 1. and 2., Business and
Properties Regulation.
Our
growth strategy could fail or present unanticipated problems for
our business in the future, which could adversely affect our
ability to make acquisitions or realize anticipated benefits of
those acquisitions.
Our growth strategy may include acquiring oil and gas businesses
and properties. We may not be able to identify suitable
acquisition opportunities or finance and complete any particular
acquisition successfully. Furthermore, acquisitions involve a
number of risks and challenges, including:
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diversion of managements attention;
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the need to integrate acquired operations;
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potential loss of key employees of the acquired companies;
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potential lack of operating experience in a geographic market of
the acquired business; and
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an increase in our expenses and working capital requirements.
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Any of these factors could adversely affect our ability to
achieve anticipated levels of cash flows from the acquired
businesses or realize other anticipated benefits of those
acquisitions.
Joint
drilling ventures and similar arrangements could expose us to
risks.
As the operator in a joint drilling venture, we could be exposed
to a risk of loss if a non-operating participant fails to meet
its obligations to fund its portion of the drilling and
operating costs as agreed under a joint operating or other
applicable agreement. In addition, as a non-operator in a joint
drilling venture, we could have limited or no ability to
influence or control the future development of non-operated
properties or
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the amount of capital expenditures that we are required to fund.
The failure of an operator to adequately perform operations, an
operators breach of the applicable agreements or an
operators failure to act in ways that are in our best
interest could reduce our production and revenues and increase
our capital expenditures and operating costs. When we are the
non-operator, our dependence on an operator and our limited
ability to influence or control operations and future
development could have a material adverse effect on our
business, financial condition or results of operations.
Severe
weather could have a material adverse impact on our
business.
Our business could be materially and adversely affected by
severe weather. Repercussions of severe weather conditions may
include:
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curtailment of services;
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weather-related damage to drilling rigs, resulting in suspension
of operations;
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weather-related damage to our facilities;
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inability to deliver materials to jobsites in accordance with
contract schedules; and
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loss of productivity.
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A
terrorist attack or armed conflict could harm our
business.
Terrorist activities, anti-terrorist efforts and other armed
conflict involving the United States 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 occurs or escalates, the resulting political instability
and societal disruption could reduce overall demand for oil and
gas, potentially putting downward pressure on demand for our
services and causing a reduction in our revenue. Oil and gas
related facilities could be direct targets for terrorist
attacks, and our operations could be adversely impacted if
significant infrastructure or facilities we use for the
production, transportation or marketing of our oil and gas
production are destroyed or damaged. Costs for insurance and
other security may increase as a result of these threats, and
some insurance coverage may become difficult to obtain, if
available at all.
Risks
Related to Our Financial Condition
We
will require additional capital to fund our future activities.
If we fail to obtain additional capital, we may not be able to
fully implement our business plan, which could lead to a decline
in reserves.
We depend on our ability to obtain financing beyond our cash
flow from operations. Historically, we have financed our
business plan and operations primarily with internally generated
cash flows, borrowings under our revolving credit facility and
issuances of common stock. We also require capital to fund our
exploration and development budget. As of December 31,
2009, approximately 57% of our total estimated proved reserves
were undeveloped. Recovery of such reserves will require
significant capital expenditures and successful drilling
operations. According to our year-end 2009 reserve report, the
estimated capital required to develop our current proved
developed and proved undeveloped oil and gas reserves is
$213 million. We will be required to meet our needs from
our internally-generated cash flows, debt financings and equity
financings.
If our revenues decrease as a result of lower commodity prices,
operating difficulties, declines in reserves or for any other
reason, we may have limited ability to obtain the capital
necessary to sustain our operations at current levels. We may,
from time to time, need to seek additional financing. Our
revolving credit facility contains covenants restricting our
ability to incur additional indebtedness without lender consent.
There can be no assurance that our bank lenders will provide
this consent or as to the availability or terms of any
additional financing. If we incur additional debt, the related
risks that we now face could intensify.
Even if additional capital is needed, we may not be able to
obtain debt or equity financing on terms favorable to us, or at
all. If cash generated by operations and available under our
revolving credit facility is not sufficient to meet our capital
requirements, the failure to obtain additional financing could
result in a
30
curtailment of our operations relating to exploration and
development of our projects, which in turn could lead to a
possible loss of properties and a decline in our oil and gas
reserves.
Our
bank lenders can limit our borrowing capabilities, which may
materially impact our operations.
At December 31, 2009, we had $32.3 million in
outstanding borrowings under our revolving credit facility, and
our borrowing base was $115 million. The borrowing base
under our revolving credit facility is redetermined
semi-annually. Redeterminations are based upon information
contained in an annual reserve report prepared by an independent
petroleum engineering firm and a mid-year report prepared by our
own engineers. In addition, as is typical in the oil and gas
industry, our bank lenders have substantial flexibility to
reduce our borrowing base on the basis of subjective factors.
Upon a redetermination, we could be required to repay a portion
of our outstanding borrowings, including the total face amounts
of all outstanding letters of credit and the amount of all
unpaid reimbursement obligations, to the extent such amounts
exceed the redetermined borrowing base. We may not have
sufficient funds to make such required repayment, which could
result in a default under the terms of the revolving credit
facility and an acceleration of the loan. We intend to finance
our development, exploration and acquisition activities with
cash flow from operations, borrowings under our revolving credit
facility and other financing activities. In addition, we may
significantly alter our capital structure to make future
acquisitions or develop our properties. Changes in our capital
structure may significantly increase our level of debt. If we
incur additional debt for these or other purposes, the related
risks that we now face could intensify. A higher debt level also
increases the risk that we may default on our debt obligations.
Our ability to meet our debt obligations and to reduce our level
of debt depends on our future performance which will be affected
by general economic conditions and financial, business and other
factors. Many of these factors are beyond our control. Our level
of debt affects our operations in several important ways,
including the following:
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a portion of our cash flow from operations is used to pay
interest on borrowings;
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the covenants contained in the agreements governing our debt
limit our ability to borrow additional funds, pay dividends,
dispose of assets or issue shares of preferred stock and
otherwise may affect our flexibility in planning for, and
reacting to, changes in business conditions;
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a high level of debt may impair our ability to obtain additional
financing in the future for working capital, capital
expenditures, acquisitions or general corporate purposes;
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a leveraged financial position would make us more vulnerable to
economic downturns and could limit our ability to withstand
competitive pressures; and
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any debt that we incur under our revolving credit facility will
be at variable rates which makes us vulnerable to increases in
interest rates.
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We
engage in commodity derivative transactions which involve risks
that can harm our business.
To manage our exposure to price risks in the marketing of our
gas production, we enter into gas price and basis differential
commodity derivative agreements. While intended to reduce the
effects of volatile gas prices and basis differentials, such
transactions may limit our potential gains and increase our
potential losses if gas prices were to rise substantially over
the price established by the commodity derivative, or if the
basis spread decreases substantially from the basis differential
established by the commodity derivative. In addition, such
transactions may expose us to the risk of loss in certain
circumstances, including instances in which our production is
less than expected, there is a widening of price differentials
between delivery points for our production and the delivery
point assumed in the commodity derivative arrangement or the
counterparties to the commodity derivative agreements fail to
perform under the contracts. In addition, as discussed above in
this Item 1A. Risk Factors, proposed
legislation relating to derivatives transactions may restrict
our ability to execute transactions to protect against risks of
fluctuating commodity prices.
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Risks
Related to Our Common Stock
Our
stock price may fluctuate significantly.
Our common stock began trading on the NASDAQ Global Market in
November 2007. In December 2008, our common stock began trading
on the NASDAQ Global Select Market. An active trading market may
not be sustained. In 2009, the average daily trading volume of
our common stock was 62,721 shares, or 0.3% of our weighted
average shares outstanding for the year. The market price of our
common stock could fluctuate significantly as a result of:
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the relatively low trading volume and resulting price swings
associated with above-average sales or purchases of our common
stock;
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actual or anticipated quarterly variations in our operating
results;
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changes in expectations as to our future financial performance
or changes in financial estimates of public market analysis;
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announcements relating our business or the business of our
competitors;
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conditions generally affecting the oil and gas industry;
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the success of our operating strategy; and
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the operating and stock price performance of other, comparable
companies.
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Many of these factors are beyond our control and we cannot
predict their potential effects on the price of our common
stock. In addition, the stock markets in general can experience
considerable price and volume fluctuations.
Future
sales of our common stock may cause our stock price to
decline.
Sales of substantial amounts 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, the sale of these shares could impair our ability to
raise capital through the sale of additional common or preferred
stock.
Common
stockholders will be diluted if additional shares are
issued.
In our initial public offering in November 2007, we sold
8.8 million shares of common stock to repay
$51.1 million outstanding on our revolving credit facility
and to repurchase 2 million shares of common stock from the
selling stockholder. In connection with the offering, we also
acquired the 30% working interest in Ozona Northeast that we did
not already own from the selling stockholder in exchange for
4.2 million shares of common stock. We may issue additional
shares of common stock, preferred stock, depositary shares,
warrants, rights, units and debt securities for general
corporate purposes, including repayment or refinancing of
borrowings, working capital, capital expenditures, investments
and acquisitions. We also issue restricted stock to our
executive officers, employees and independent directors as part
of their compensation. If we issue additional shares of our
common stock in the future, it may have a dilutive effect on our
current outstanding stockholders.
The
equity trading markets may be volatile, which could result in
losses for our stockholders.
The equity trading markets may experience periods of volatility,
which could result in highly variable and unpredictable pricing
of equity securities. The market price of our common stock could
change in ways that may or may not be related to our business,
our industry or our operating performance and financial
condition.
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Item 1B.
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Unresolved
Staff Comments.
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None.
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Item 3.
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Legal
Proceedings.
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Approach Operating, LLC v. EnCana Oil & Gas
(USA) Inc., Cause No. 29.070A, District Court of
Limestone County, Texas. On July 2, 2009 our operating
subsidiary filed a lawsuit against EnCana Oil & Gas
(USA) Inc., or EnCana, for breach of the joint operating
agreement, or JOA, covering our North Bald Prairie project in
East Texas and seeking damages for nonpayment of amounts owed
under the JOA as well as declaratory relief. We contend that
such amounts owed by EnCana are at least $2.1 million, plus
attorneys fees, costs and other amounts to which we might
be entitled under law or in equity. As we previously have
disclosed, in December 2008, EnCana notified us that it was
exercising its right to become operator of record for joint
interest wells in North Bald Prairie under an operator election
agreement between the parties. EnCana contends that it does not
owe us for part or all of joint interest billings incurred after
EnCana provided us with notice of EnCanas election to
assume operatorship in December 2008. EnCana also contends that
certain of the disputed operations were unnecessary, while other
charges are improper because we failed to obtain EnCanas
consent under the JOA prior to undertaking the operations. We
have informed the Court that we will transfer operatorship to
EnCana when EnCana has made all payments it owes under the JOA.
Regardless of the outcome of this proceeding, the JOA provides
that either party (operator or non-operator) may propose the
drilling of wells.
We also are involved in various other legal and regulatory
proceedings arising in the normal course of business. While we
cannot predict the outcome of these proceedings with certainty,
we do not believe that an adverse result in any pending legal or
regulatory proceeding, individually or in the aggregate, would
be material to our consolidated financial condition or cash
flows; however, an unfavorable outcome could have a material
adverse effect on our results of operations for a specific
interim period or year.
|
|
Item 4.
|
(Removed
and Reserved).
|
33
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities.
|
Market
Information
Our common stock is traded on NASDAQ in the United States under
the symbol AREX. During 2009, trading volume
averaged 62,721 shares per day. The following table shows
the quarterly high and low sale prices of our common stock as
reported on NASDAQ for the past two years.
|
|
|
|
|
|
|
|
|
|
|
High
|
|
Low
|
|
2009
|
|
|
|
|
|
|
|
|
First quarter
|
|
$
|
8.90
|
|
|
$
|
3.20
|
|
Second quarter
|
|
|
10.47
|
|
|
|
5.13
|
|
Third quarter
|
|
|
9.77
|
|
|
|
6.38
|
|
Fourth quarter
|
|
|
10.19
|
|
|
|
6.24
|
|
2008
|
|
|
|
|
|
|
|
|
First quarter
|
|
$
|
17.38
|
|
|
$
|
9.20
|
|
Second quarter
|
|
|
28.87
|
|
|
|
15.17
|
|
Third quarter
|
|
|
30.00
|
|
|
|
9.92
|
|
Fourth quarter
|
|
|
14.25
|
|
|
|
5.39
|
|
Holders
As of February 28, 2010, there were 37 record holders of
our common stock. In many instances, a record holder is a broker
or other entity holding shares in street name for one or more
customers who beneficially own the shares.
Dividends
We have not paid any cash dividends on our common stock. We do
not expect to pay any cash or other dividends in the foreseeable
future on our common stock, as we intend to reinvest cash flow
generated by operations in our business. Our revolving credit
facility currently restricts our ability to pay cash dividends
on our common stock, and we may also enter into credit
agreements or other borrowing arrangements in the future that
restrict or limit our ability to pay cash dividends on our
common stock.
Securities
Authorized for Issuance under Equity Compensation
Plans
The following table sets forth information regarding securities
authorized for issuance under equity compensation plans and
individual compensation arrangements as of December 31,
2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
(b)
|
|
(c)
|
|
|
Number of
|
|
Weighted-
|
|
Number of Securities
|
|
|
Securities to be
|
|
Average Exercise
|
|
Remaining Available for
|
|
|
Issued Upon
|
|
Price of
|
|
Future Issuance Under
|
|
|
Exercise of
|
|
Outstanding
|
|
Equity Compensation
|
|
|
Outstanding
|
|
Options,
|
|
Plans (Excluding
|
|
|
Options, Warrants
|
|
Warrants and
|
|
Securities Reflected in
|
Plan Category
|
|
and Rights
|
|
Rights
|
|
Column (a))
|
|
Equity compensation plans approved by stockholders
|
|
|
409,327
|
|
|
$
|
8.03
|
|
|
|
1,242,064
|
|
Equity compensation plans not approved by stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
34
Performance
Graph
The following graph compares the cumulative return on a $100
investment in our common stock from November 8, 2007,
through December 31, 2009, to that of the cumulative return
on a $100 investment in the Standard & Poors
500, or S&P 500, index and the Dow Jones
U.S. Exploration & Production Total Stock Market,
or TSM, index for the same period. In calculating the cumulative
return, reinvestment of dividends, if any, is assumed. This
graph is not soliciting material, is not deemed
filed with the SEC and is not to be incorporated by reference in
any of our filings under the Securities Act or the Exchange Act,
whether made before or after the date hereof and irrespective of
any general incorporation language in any such filing.
Comparison
of Total Return from November 8, 2007 through
December 31, 2009
Among Approach Resources Inc., the S&P 500 Index and
the Dow Jones U.S. Exploration & Production TSM
Index
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11/8/2007
|
|
12/31/2007
|
|
12/31/2008
|
|
12/31/2009
|
|
|
|
Approach Resources Inc.
|
|
$
|
100.00
|
|
|
$
|
102.14
|
|
|
$
|
58.06
|
|
|
$
|
61.32
|
|
S&P 500
|
|
|
100.00
|
|
|
|
95.15
|
|
|
|
59.95
|
|
|
|
75.81
|
|
D J U.S. Exploration & Production TSM
|
|
|
100.00
|
|
|
|
101.09
|
|
|
|
59.62
|
|
|
|
84.37
|
|
|
|
Recent
Sales of Unregistered Securities; Uses of Proceeds From
Registered Securities
We did not sell any securities during the year ended
December 31, 2009 that were not registered under the
Securities Act.
Issuer
Repurchases of Equity Securities
We adopted the Approach Resources Inc. 2007 Stock Incentive Plan
effective as of June 28, 2007, and amended it effective
December 31, 2008. The 2007 Stock Incentive Plan allows us
to withhold shares of common stock to pay withholding taxes
payable upon vesting of a restricted stock grant. The number of
shares of common stock available for grants under the 2007 Stock
Incentive Plan is increased by the number of shares withheld as
payment of such withholding taxes. The following table shows the
number of shares of
35
common stock withheld to satisfy the income tax withholding
obligations arising upon the vesting of restricted shares issued
to employees under the 2007 Stock Incentive Plan.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(d)
|
|
|
|
|
|
|
|
|
Maximum
|
|
|
|
|
|
|
|
|
Number (or
|
|
|
|
|
|
|
(c)
|
|
Approximate
|
|
|
|
|
|
|
Total Number of
|
|
Dollar Value) of
|
|
|
(a)
|
|
|
|
Shares Purchased
|
|
Shares (or Units)
|
|
|
Total
|
|
(b)
|
|
as Part of
|
|
that May Yet be
|
|
|
Number of
|
|
Average
|
|
Publicly
|
|
Purchased Under
|
|
|
Shares
|
|
Price Paid
|
|
Announced Plans
|
|
the Plans or
|
Period
|
|
Purchased
|
|
per Share
|
|
or Programs
|
|
Programs
|
|
October 1, 2009 October 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
November 1, 2009 November 30, 2009
|
|
|
5,835
|
|
|
$
|
7.50
|
|
|
|
|
|
|
|
|
|
December 1, 2009 December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
5,835
|
|
|
$
|
7.50
|
|
|
|
|
|
|
|
|
|
36
|
|
Item 6.
|
Selected
Financial Data.
|
The following table sets forth selected financial information
for the five years ended December 31, 2009. All weighted
average shares and per share data have been adjusted for the
three-for-one stock split and the stock issuance resulting from
the combination of Approach Oil & Gas Inc., or AOG,
under a contribution agreement effective November 14, 2007.
This information should be read in conjunction with Item 7
of this report, Managements Discussion and Analysis
of Financial Condition and Results of Operations, and our
consolidated financial statements, related notes and other
financial information included in this report.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per-share data)
|
|
|
Operating Results Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
40,648
|
|
|
$
|
79,869
|
|
|
$
|
39,114
|
|
|
$
|
46,672
|
|
|
$
|
43,264
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
7,777
|
|
|
|
7,621
|
|
|
|
3,815
|
|
|
|
3,889
|
|
|
|
2,910
|
|
Severance and production taxes
|
|
|
1,996
|
|
|
|
4,202
|
|
|
|
1,659
|
|
|
|
1,736
|
|
|
|
1,975
|
|
Exploration
|
|
|
1,621
|
|
|
|
1,478
|
|
|
|
883
|
|
|
|
1,640
|
|
|
|
733
|
|
Impairment of unproved properties
|
|
|
2,964
|
|
|
|
6,379
|
|
|
|
267
|
|
|
|
558
|
|
|
|
|
|
General and administrative
|
|
|
10,617
|
|
|
|
8,881
|
|
|
|
12,667
|
|
|
|
2,416
|
|
|
|
2,659
|
|
Depletion, depreciation and amortization
|
|
|
24,660
|
|
|
|
23,710
|
|
|
|
13,098
|
|
|
|
14,551
|
|
|
|
8,011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
49,635
|
|
|
|
52,271
|
|
|
|
32,389
|
|
|
|
24,790
|
|
|
|
16,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
|
(8,987
|
)
|
|
|
27,598
|
|
|
|
6,725
|
|
|
|
21,882
|
|
|
|
26,976
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of investment
|
|
|
|
|
|
|
(917
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(1,787
|
)
|
|
|
(1,269
|
)
|
|
|
(5,219
|
)
|
|
|
(3,814
|
)
|
|
|
(802
|
)
|
Realized gain on commodity derivatives
|
|
|
14,659
|
|
|
|
2,936
|
|
|
|
4,732
|
|
|
|
6,222
|
|
|
|
(2,925
|
)
|
Unrealized (loss) gain on commodity derivatives
|
|
|
(9,899
|
)
|
|
|
7,149
|
|
|
|
(3,637
|
)
|
|
|
8,668
|
|
|
|
(4,163
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before (benefit) provision for income taxes
|
|
|
(6,014
|
)
|
|
|
35,497
|
|
|
|
2,601
|
|
|
|
32,958
|
|
|
|
19,086
|
|
(Benefit) provision for income taxes
|
|
|
(785
|
)
|
|
|
12,111
|
|
|
|
(108
|
)
|
|
|
11,756
|
|
|
|
7,028
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(5,229
|
)
|
|
$
|
23,386
|
|
|
$
|
2,709
|
|
|
$
|
21,202
|
|
|
$
|
12,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.25
|
)
|
|
$
|
1.13
|
|
|
$
|
0.25
|
|
|
$
|
2.26
|
|
|
$
|
1.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
(0.25
|
)
|
|
$
|
1.12
|
|
|
$
|
0.24
|
|
|
$
|
2.20
|
|
|
$
|
1.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Cash Flows Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
39,761
|
|
|
$
|
56,435
|
|
|
$
|
30,746
|
|
|
$
|
34,305
|
|
|
$
|
40,588
|
|
Investing activities
|
|
|
(29,553
|
)
|
|
|
(100,633
|
)
|
|
|
(52,940
|
)
|
|
|
(59,384
|
)
|
|
|
(72,224
|
)
|
Financing activities
|
|
|
(11,618
|
)
|
|
|
43,696
|
|
|
|
22,062
|
|
|
|
26,771
|
|
|
|
32,199
|
|
Effect of Canadian exchange rate
|
|
|
18
|
|
|
|
(206
|
)
|
|
|
6
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2,685
|
|
|
$
|
4,077
|
|
|
$
|
4,785
|
|
|
$
|
4,911
|
|
|
$
|
3,219
|
|
Other current assets
|
|
|
9,318
|
|
|
|
30,760
|
|
|
|
12,021
|
|
|
|
12,792
|
|
|
|
15,701
|
|
Property, equipment, net, successful efforts method
|
|
|
304,483
|
|
|
|
303,404
|
|
|
|
230,819
|
|
|
|
132,520
|
|
|
|
89,407
|
|
Other assets
|
|
|
2,440
|
|
|
|
|
|
|
|
1,101
|
|
|
|
86
|
|
|
|
89
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
318,926
|
|
|
$
|
338,241
|
|
|
$
|
248,726
|
|
|
$
|
150,309
|
|
|
$
|
108,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
21,996
|
|
|
$
|
30,775
|
|
|
$
|
22,017
|
|
|
$
|
15,421
|
|
|
$
|
32,746
|
|
Long-term debt
|
|
|
32,319
|
|
|
|
43,537
|
|
|
|
|
|
|
|
47,619
|
|
|
|
29,425
|
|
Other long-term liabilities
|
|
|
44,115
|
|
|
|
40,116
|
|
|
|
26,890
|
|
|
|
17,697
|
|
|
|
6,555
|
|
Stockholders equity
|
|
|
220,496
|
|
|
|
223,813
|
|
|
|
199,819
|
|
|
|
69,572
|
|
|
|
39,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
318,926
|
|
|
$
|
338,241
|
|
|
$
|
248,726
|
|
|
$
|
150,309
|
|
|
$
|
108,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
|
The following discussion is intended to assist in understanding
our results of operations and our financial condition. Our
consolidated financial statements and the accompanying notes
included elsewhere in this report contain additional information
that should be referred to when reviewing this material.
Statements in this discussion may be forward-looking. These
forward-looking statements involve risks and uncertainties,
which could cause actual results to differ from those expressed.
See Cautionary Statement Regarding Forward-Looking
Statements at the beginning of this report and Risk
Factors in Item 1.A for additional discussion of some
of these factors and risks.
Overview
We are an independent energy company engaged in the exploration,
development, production and acquisition of natural gas and oil
properties. We focus on natural gas and oil reserves in tight
sands and shale and have leasehold interests totaling
approximately 273,482 gross (196,634 net) acres as of
December 31, 2009. Our management team has a proven track
record of finding and exploiting unconventional reservoirs
through advanced completion, fracturing and drilling techniques.
As the operator all of our production and proved reserves, we
have a high degree of control over capital expenditures and
other operating matters.
We currently operate or have interests in the following areas:
West
Texas
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Ozona Northeast (Wolfcamp, Canyon Sands, Strawn and Ellenburger)
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Cinco Terry (Wolfcamp, Canyon Sands and Ellenburger)
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East
Texas
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North Bald Prairie (Cotton Valley Sand, Bossier Shale and Cotton
Valley Lime)
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Northern
New Mexico
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El Vado East (Mancos Shale)
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Southwest
Kentucky
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Boomerang (New Albany Shale)
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At December 31, 2009, we owned working interests in 467
producing oil and gas wells, had estimated proved reserves of
approximately 218.9 Bcfe and were producing
21.7 MMcfe/d, based on production for December 2009. Our
2010 average daily production through February was
22 MMcfe/d.
At December 31, 2009, all of our proved reserves and
production were located in Ozona Northeast and Cinco Terry in
West Texas and in North Bald Prairie in East Texas. At year end
2009, our proved reserves were 77% natural gas, 43% proved
developed and had a reserve life index of over 20 years,
based on 2009 production of 8,808 MMcfe. In addition to our
producing wells, we had identified 1,311 total drilling
locations in Ozona Northeast, Cinco Terry and North Bald Prairie
at December 31, 2009, of which 385 are proved.
Our average realized price for natural gas, oil and NGLs (before
the effect of commodity derivatives transactions) decreased
55.4%, 41.4% and 37.7%, respectively, from 2008 to 2009. As a
result, we reduced capital expenditures and drilling activity,
paid down long-term debt and increased our liquidity by over
40%, from $60.5 million at December 31, 2008 to
$85.4 million at December 31, 2009. We define
liquidity as funds available under our credit facility plus
year-end cash and cash equivalents. At December 31, 2009,
we had $32.3 million in long-term debt outstanding under
our revolving credit facility, compared to $43.5 million at
December 31, 2008. Another result of reduced drilling
activity, plus the natural decline of our tight gas fields, was
a decline in our average daily production. Average daily
production declined from 28.1 MMcfe/d for the three months
ended March 31, 2009, to 21.6 MMcfe/d for the three
months ended December 31, 2009.
38
We resumed drilling during September 2009 and currently are
operating two rigs in Cinco Terry and one rig in Ozona
Northeast. Also in the fourth quarter of 2009, we began
acquiring
3-D seismic
data across 128.4 square miles, or 82,176 acres, in
our Cinco Terry field. We completed the acquisition of
3-D seismic
data across our Cinco Terry field in February 2010. Our
3-D seismic
data inventory now covers over 135,000 acres in the Permian
Basin. Interpretation of the data is expected to be complete by
June 2010.
We realize higher oil and NGL volumes in Cinco Terry than in
Ozona Northeast (where we have a sales contract that does not
include processing of NGLs) or North Bald Prairie (where
substantially all of our production is dry gas). Therefore, as
we have continued to develop Cinco Terry, we have increased the
oil and NGL component of our overall production and reserves. In
addition, our contract in Ozona Northeast expires in the first
quarter of 2011, after which time we expect to begin processing
NGLs in Ozona Northeast. Excluding the effect of any future
acquisitions, we expect that further development of Cinco Terry
in 2010 and beyond, along with processing gas in Ozona Northeast
in 2011 and beyond, will continue to increase the oil and NGL
component of our production and reserve in the future.
Segment reporting is not applicable to us as we have a single,
company-wide management team that administers all properties as
a whole rather than by discrete operating segments. We track
only basic operational data by area. We do not maintain complete
separate financial statement information by area. We measure
financial performance as a single enterprise and not on an
area-by-area
basis.
Our financial results depend upon many factors, particularly the
price of oil and gas. Commodity prices are affected by changes
in market demand, which is impacted by overall economic
activity, weather, pipeline capacity constraints, estimates of
inventory storage levels, gas price differentials and other
factors. As a result, we cannot accurately predict future oil
and gas prices, and therefore, we cannot determine what effect
increases or decreases will have on our capital program,
production volumes and future revenues. A substantial or
extended decline in oil and gas prices could have a material
adverse effect on our business, financial condition, results of
operations, quantities of oil and gas reserves that may be
economically produced and liquidity that may be accessed through
our borrowing base under our revolving credit facility and
through capital markets.
In addition to production volumes and commodity prices, finding
and developing sufficient amounts of oil and gas reserves at
economical costs are critical to our long-term success. Future
finding and development costs are subject to changes in the
industry, including the costs of acquiring, drilling and
completing our projects. We focus our efforts on increasing oil
and gas reserves and production while controlling costs at a
level that is appropriate for long-term operations. Our future
cash flow from operations will depend on our ability to manage
our overall cost structure.
Like all oil and gas production companies, we face the challenge
of natural production declines. Oil and gas production from a
given well naturally decreases over time. Additionally, our
reserves have a rapid initial decline. We attempt to overcome
this natural decline by drilling to develop and identify
additional reserves, farm-ins or other joint drilling ventures,
and by acquisitions. However, during times of severe price
declines, we may from time to time reduce current capital
expenditures and curtail drilling operations in order to
preserve liquidity. A material reduction in capital expenditures
and drilling activities could materially reduce our production
volumes and revenues from pre-2009 levels and increase future
expected costs necessary to develop existing reserves. As
discussed above, due to the extended decline of oil and natural
gas prices, we released our remaining rigs during the first week
of April 2009. The natural decline of our tight gas fields and
reduced drilling activity has caused a decline in our average
daily production since the three months ended March 31,
2009.
We also face the challenge of financing future acquisitions. We
believe we have adequate unused borrowing capacity under our
revolving credit facility for possible acquisitions, temporary
working capital needs and any expansion of our drilling program.
Funding for future acquisitions also may require additional
sources of financing, which may not be available.
39
Critical
Accounting Policies and Estimates
The discussion and analysis of our financial condition and
results of operations are based upon our consolidated financial
statements, which have been prepared in accordance with
accounting policies generally accepted in the United States. The
preparation of our consolidated financial statements requires us
to make estimates and assumptions that affect our reported
results of operations and the amount of reported assets,
liabilities and proved oil and gas reserves. Some accounting
policies involve judgments and uncertainties to such an extent
that there is reasonable likelihood that materially different
amounts could have been reported under different conditions, or
if different assumptions had been used. Actual results may
differ from the estimates and assumptions used in the
preparation of our consolidated financial statements. Described
below are the most significant policies we apply in preparing
our consolidated financial statements, some of which are subject
to alternative treatments under GAAP. We also describe the most
significant estimates and assumptions we make in applying these
policies. See Note 1 to our consolidated financial
statements.
Oil
and Gas Activities Successful Efforts
Accounting for oil and gas activities is subject to special,
unique rules. We use the successful efforts method of accounting
for our oil and gas activities. The significant principles for
this method are:
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geological and geophysical evaluation costs are expensed as
incurred;
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dry holes for exploratory wells are expensed, and dry holes for
developmental wells are capitalized; and
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capitalized costs related to proved oil and gas properties,
including wells and related equipment and facilities, are
evaluated for impairment based on an analysis of undiscounted
future net cash flows in accordance with ASC 360. If
undiscounted cash flows are insufficient to recover the net
capitalized costs related to proved properties, then we
recognize an impairment charge in income from operations equal
to the difference between the net capitalized costs related to
proved properties and their estimated fair values based on the
present value of the related future net cash flows. We noted no
impairment of our proved properties based on our analysis for
the years ended December 31, 2009, 2008 or 2007.
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Proved
Reserves
On December 31, 2008, the SEC released a Final Rule,
Modernization of Oil and Gas Reporting, approving
revisions designed to modernize oil and gas reserve reporting
requirements. The new reserve rules are effective for our
financial statements for the year ended December 31, 2009
and our 2009 year-end proved reserve estimates. The most
significant revisions to the reporting requirements include:
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Commodity prices. Economic producibility of
reserves is now based on the unweighted, arithmetic average of
the closing price on the first day of the month for the
12-month
period prior to fiscal year end, unless prices are defined by
contractual arrangements;
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Undeveloped oil and gas reserves. Reserves may
be classified as proved undeveloped for undrilled
areas beyond one offsetting drilling unit from a producing well
if there is reasonable certainty that the quantities will be
recovered;
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Reliable technology. The rules now permit the
use of new technologies to establish the reasonable certainty of
proved reserves if those technologies have been demonstrated
empirically to lead to reliable conclusions about reserves
volumes;
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Unproved reserves. Probable and possible
reserves may be disclosed separately on a voluntary basis;
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Preparation of reserves estimates. Disclosure
is required regarding the internal controls used to assure
objectivity in the reserves estimation process and the
qualifications of the technical person primarily responsible for
preparing reserves estimates; and
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Third party reports. We are now required to
file the report of any third party used to prepare or audit
reserves our estimates.
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40
In addition, in January 2010, FASB issued Account Standards
Update, or the Update,
2010-03,
Oil and Gas Reserve Estimation and Disclosures, to
provide consistency with the new reserve rules. The Update
amends existing standards to align the reserves calculation and
disclosure requirements under GAAP with the requirements in the
SECs reserve rules. We adopted the new standards effective
December 31, 2009. The new standards are applied
prospectively as a change in estimate.
For the year ended December 31, 2009, we engaged DeGolyer
and MacNaughton, independent petroleum engineers, to prepare
independent estimates of the extent and value of the proved
reserves associated with certain of our oil and gas properties
in accordance with guidelines established by the SEC, including
the recent revisions designed to modernize oil and gas reserve
reporting requirements. We adopted these revisions effective
December 31, 2009.
Estimates of proved oil and gas reserves directly impact
financial accounting estimates including depletion, depreciation
and amortization expense, evaluation of impairment of properties
and the calculation of plugging and abandonment liabilities.
Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically
producible from a given date forward, from known
reservoirs, and under existing economic conditions, operating
methods, and government regulations The process of estimating
quantities of proved reserves is very complex, requiring
significant subjective decisions in the evaluation of all
geological, engineering and economic data for each reservoir.
The data for any reservoir may change substantially over time
due to results from operational activity. Proved reserve volumes
at December 31, 2009, were estimated based on the
unweighted, arithmetic average of the closing price on the first
day of each month for the
12-month
period prior to December 31, 2009 for natural gas, oil and
NGLs in accordance with new reserve rules.
The new reserve rules resulted in the use of lower prices for
natural gas, oil and NGLs than would have resulted under the
previous reporting requirements. Under the new reserve rules,
our estimated proved reserves increased by 7,860 MMcfe.
Under the previous reserve rules, our estimated total proved
reserves of natural gas, oil and NGLs would have increased by
20,122 MMcfe. Therefore, the effect of the new reserve
rules was a negative revision of 12,262 MMcfe.
Changes in commodity prices and operation costs may also affect
the overall evaluation of reservoirs. A hypothetical 10% decline
in our December 31, 2009 estimated proved reserves would
have increased our depletion expense by approximately $625,000
for the year ended December 31, 2009. Under previous
reserve rules (year-end 2009 spot prices for natural gas, oil
and NGLs), our depletion expense would have decreased by
approximately $400,000.
See also Items 1 and 2. Business and
Properties Proved Oil and Gas Reserves and
Note 12 to our consolidated financial statements for
additional information regarding our estimated proved reserves.
Derivative
Instruments and Commodity Derivative Activities
Unrealized gains and losses, at fair value, are included on our
consolidated balance sheets as current or non-current assets or
liabilities based on the anticipated timing of cash settlements
under the related contracts. Changes in the fair value of our
commodity derivative contracts are recorded in earnings as they
occur and included in other income (expense) on our consolidated
statements of operations. We estimate the fair values of swap
contracts based on the present value of the difference in
exchange-quoted forward price curves and contractual settlement
prices multiplied by notional quantities. We internally valued
the collar contracts using industry-standard option pricing
models and observable market inputs. We use our internal
valuations to determine the fair values of the contracts that
are reflected on our consolidated balance sheets. Realized gains
and losses are also included in other income (expense) on our
consolidated statements of operations.
We are exposed to credit losses in the event of nonperformance
by the counterparties on our commodity derivatives positions and
have considered the exposure in our internal valuations.
However, we do not anticipate nonperformance by the
counterparties over the term of the commodity derivatives
positions.
Changes in the derivatives fair value are currently
recognized in the statement of operations unless specific
commodity derivative hedge accounting criteria are met and such
strategies are designated. For
41
qualifying cash-flow commodity derivatives, the gain or loss on
the derivative is deferred in accumulated other comprehensive
(loss) income to the extent the commodity derivative is
effective. The ineffective portion of the commodity derivative
is recognized immediately in the statement of operations. Gains
and losses on commodity derivative instruments included in
accumulated other comprehensive (loss) income are reclassified
to oil and gas sales revenue in the period that the related
production is delivered. Derivative contracts that do not
qualify for commodity derivative accounting treatment are
recorded as derivative assets and liabilities at fair value in
the balance sheet, and the associated unrealized gains and
losses are recorded as current income or expense in the
statement of operations.
Historically, we have not designated our derivative instruments
as cash-flow hedges. We record our open derivative instruments
at fair value on our consolidated balance sheets as either
unrealized gains or losses on commodity derivatives. We record
changes in such fair value in earnings on our consolidated
statements of operations under the caption entitled
unrealized (loss) gain on commodity derivatives.
Although we have not designated our derivative instruments as
cash-flow hedges, we use those instruments to reduce our
exposure to fluctuations in commodity prices related to our oil
and gas production. Accordingly, we record realized gains and
losses under those instruments in other revenues on our
consolidated statements of operations. For the years ended
December 31, 2009 and 2007, we recognized an unrealized
loss of $9.9 million and $3.6 million, respectively,
from the change in the fair value of commodity derivatives. For
the year ended December 31, 2008, we recognized an
unrealized gain of $7.1 million from the change in the fair
value of commodity derivatives. A hypothetical 10% increase in
the NYMEX floating prices would have resulted in a
$2.7 million decrease in the December 31, 2009 fair
value recorded on our balance sheet, and a corresponding
increase to the loss on commodity derivatives in our statement
of operations.
Asset
Retirement Obligation
Our asset retirement obligation primarily represents the
estimated present value of the amount we will incur to plug,
abandon and remediate our producing properties at the end of
their productive lives, in accordance with applicable federal,
state and local laws. We determine our asset retirement
obligation by calculating the present value of estimated cash
flows related to the liability. The retirement obligation is
recorded as a liability at its estimated present value as of the
assets inception, with an offsetting increase to proved
properties. Periodic accretion of discount of the estimated
liability is recorded as an expense in the income statement.
Our liability is determined using significant assumptions,
including current estimates of plugging and abandonment costs,
annual inflation of these costs, the productive lives of wells
and our risk-adjusted interest rate. Changes in any of these
assumptions can result in significant revisions to the estimated
asset retirement obligation.
Share-Based
Compensation
Our 2007 Stock Incentive Plan allows grants of stock and options
to employees and outside directors. Granting of awards may
increase our general and administrative expenses subject to the
size and timing of the grants. See Note 5 to our
consolidated financial statements.
We measure and record compensation expense for all share-based
payment awards to employees and outside directors based on
estimated grant-date fair values. Compensation costs for awards
granted are recognized over the requisite service period based
on the grant-date fair value.
The fair value of each option granted was estimated using an
option-pricing model with the following weighted average
assumptions during the years ended December 31, 2008 and
2007. There were no stock option grants during the year ended
December 31, 2009.
42
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2008
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2007
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Expected dividends
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Expected volatility
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64
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%
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68
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%
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Risk-free interest rate
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2.7
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%
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3.9
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%
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Expected life
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6 years
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6 years
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We have not paid out dividends historically, thus the dividend
yields are estimated at zero percent.
Since our shares were not publicly traded prior to our initial
public offering on November 8, 2007, we used an average of
historical volatility rates based upon other companies within
our industry. Management believes that these average historical
volatility rates are currently the best available indicator of
expected volatility.
The risk-free interest rate is the implied yield available for
zero-coupon U.S. government issues with a remaining term of
five years.
The expected lives of our options are determined based on the
term of the option using the simplified method outlined in Staff
Accounting Bulletin 110.
Assumptions are reviewed each time there is a new grant and may
be impacted by actual fluctuation in our stock price, movements
in market interest rates and option terms. The use of different
assumptions produces a different fair value for the options
granted or modified and impacts the amount of compensation
expense recognized on the consolidated statement of operations.
Recent
Accounting Pronouncements
In January 2010, the Financial Accounting Standards Board, or
the FASB, issued amendments to Fair Value Measurements and
Disclosures under ASC
820-10.
Effective for the year ended December 31, 2010, this
guidance provides for disclosures of significant transfers in an
out of Levels 1 and 2. In addition, the guidance clarifies
existing disclosure requirements regarding inputs and valuation
techniques as well as the appropriate level of disaggregation
for fair value measurements and disclosures. Effective for the
year ending December 31, 2011, this guidance provides for
disclosures of activity on a gross basis within Level 3
reconciliation. We do not expect this standard to have a
significant impact on our financial position or results of
operations.
Effects
of Inflation
Inflation in the United States has been relatively low in recent
years and did not have a material impact on our results of
operations for the years ended December 31, 2009, 2008 or
2007. Although the impact of inflation has been insignificant in
recent years, it is still a factor in the United States economy
and may increase the cost to acquire or replace property, plant
and equipment. It may also increase the cost of labor or
supplies. To the extent permitted by competition, regulation and
our existing agreements, we have and will continue to pass along
increased costs to our customers in the form of higher prices.
43
Results
of Operations
Years
Ended December 31, 2009 and 2008
The following table sets forth summary information regarding
natural gas, oil and NGL revenues, production, average product
prices and average production costs and expenses for the last
two years. Oil and NGLs are converted at the rate of one Bbl
equals six Mcf.
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Years Ended
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December 31,
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2009
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2008
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Revenues (in thousands)
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Gas
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$
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23,406
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$
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58,819
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Oil
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11,323
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16,413
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NGLs
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5,919
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4,637
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Total oil and gas sales
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40,648
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79,869
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Realized gain on commodity derivatives
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14,659
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2,936
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Total oil and gas sales including derivative impact
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$
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55,307
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$
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82,805
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Production
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Gas (MMcf)
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6,320
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7,092
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Oil (MBbls)
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206
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175
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NGLs (MBbls)
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209
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102
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Total (MMcfe)
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8,808
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8,755
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Total (MMcfe/d)
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24.1
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23.9
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Average prices
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Gas (per Mcf)
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$
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3.70
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$
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8.29
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Oil (per Bbl)
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54.97
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93.79
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NGLs (per Bbl)
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28.32
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45.46
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Total (per Mcfe)
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$
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4.61
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$
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9.12
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Realized gain on commodity derivatives (per Mcfe)
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1.66
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0.34
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Total including derivative impact (per Mcfe)
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$
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6.27
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$
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9.46
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Costs and expenses (per Mcfe)
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Lease operating(1)
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$
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0.88
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$
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0.87
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Severance and production taxes
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0.23
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0.48
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Exploration
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|
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0.18
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0.17
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Impairment of unproved properties
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0.34
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0.73
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General and administrative
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1.21
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1.01
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Depletion, depreciation and amortization
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2.80
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2.71
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|
(1) |
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Lease operating expenses per Mcfe includes ad valorem taxes. |
Oil and gas production. Production for the
year ended December 31, 2009 totaled 8.8 Bcfe
(24.1 MMcfe/d), compared to 8.8 Bcfe
(23.9 MMcfe/d) produced in the prior year. Production for
the year ended December 31, 2009 was 72% natural gas and
28% oil and NGLs, compared to 81% natural gas and 19% oil and
NGLs in prior year period. We expect production to increase
slightly in 2010.
Oil and gas sales. Oil and gas sales decreased
$39.2 million, or 49.2%, for the year ended
December 31, 2009 to $40.6 million from
$79.9 million for the year ended December 31, 2008.
The decrease in oil and gas sales principally resulted from
sharp decreases in the price we received for our natural gas,
oil and NGL production. The average price we received for our
production, before the effect of commodity derivatives,
decreased from $9.12 per Mcfe to $4.61 per Mcfe, or a 49.5%
decrease. Of the $39.2 million decrease in revenues,
approximately $41.1 million was attributable to a decrease
in oil and gas prices, partially offset by $1.9 million in
revenues attributable to a slight increase in production volumes
over the prior year.
44
Commodity derivative activities. Realized
losses and gains from our commodity derivative activity
increased our earnings by $14.7 million and
$2.9 million for the years ended December 31, 2009 and
2008, respectively. Realized gains and losses are derived from
the relative movement of gas prices in relation to the range of
prices in our collars or the fixed notional pricing for the
respective years. The unrealized loss on commodity derivatives
was $9.9 million for 2009 and the unrealized gain on
commodity derivatives was $7.1 million for 2008. As natural
gas commodity prices increase, the fair value of the open
portion of those positions decreases. The unrealized loss for
2009 primarily resulted from the settlement of derivative
contracts which were outstanding at December 31, 2008. As
natural gas commodity prices decrease, the fair value of the
open portion of those positions increases. Historically, we have
not designated our derivative instruments as cash-flow hedges.
We record our open derivative instruments at fair value on our
consolidated balance sheets as either unrealized gains or losses
on commodity derivatives. We record changes in such fair value
in earnings on our consolidated statements of operations under
the caption entitled unrealized (loss) gain on commodity
derivatives.
Lease operating expense. Our lease operating
expenses, or LOE, increased $156,000, or 2%, for the year ended
December 31, 2009 to $7.8 million ($0.88 per Mcfe)
from $7.6 million ($0.87 per Mcfe) for the year ended
December 31, 2008. Increases in ad valorem taxes and
pumpers and supervision costs were partially offset by decreases
in well repair and maintenance and workover costs. On a per Mcfe
basis, we expect LOE to remain relatively constant in 2010.
Following is a summary of lease operating expenses (per Mcfe):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
% Change
|
|
|
Compressor rental and repair
|
|
$
|
0.29
|
|
|
$
|
0.28
|
|
|
$
|
0.01
|
|
|
|
3.6
|
%
|
Pumpers and supervision
|
|
|
0.17
|
|
|
|
0.14
|
|
|
|
0.03
|
|
|
|
21.4
|
|
Ad valorem taxes
|
|
|
0.18
|
|
|
|
0.15
|
|
|
|
0.03
|
|
|
|
20.0
|
|
Well repair and maintenance
|
|
|
0.09
|
|
|
|
0.13
|
|
|
|
(0.04
|
)
|
|
|
(30.8
|
)
|
Water hauling, insurance and other
|
|
|
0.14
|
|
|
|
0.13
|
|
|
|
0.01
|
|
|
|
7.7
|
|
Workovers
|
|
|
0.01
|
|
|
|
0.04
|
|
|
|
(0.03
|
)
|
|
|
(75.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
0.88
|
|
|
$
|
0.87
|
|
|
$
|
0.01
|
|
|
|
1.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and production taxes. Our production
taxes decreased $2.2 million, or 52.5%, for the year ended
December 31, 2009 to $2 million from $4.2 million
for the year ended December 31, 2008. The decrease in
production taxes was a function of the decrease in oil and gas
sales between 2009 and 2008. Severance and production taxes
amounted to approximately 4.9% and 5.3% of oil and gas sales for
December 31, 2009 and 2008, respectively. We expect
severance and production taxes to be between 5% and 6% of
revenues during 2010.
Exploration. We recorded $1.6 million of
exploration expense for the year ended December 31, 2009,
compared to $1.5 million for the year ended
December 31, 2008. Exploration expense in the 2009 period
resulted primarily from
3-D seismic
acquired across our Cinco Terry field and the expiration of
leases in our Ozona Northeast and North Bald Prairie fields.
Exploration expense for the 2008 period resulted from one dry
hole drilled in Ozona Northeast and $965,000 of lease extensions
in Ozona Northeast. Due to additional 3-D expenses from the
seismic acquisition across Cinco Terry, lease renewals and
expirations, and potential exploration costs in Northern New
Mexico, we expect exploration expense to increase in 2010.
Impairment of oil and gas properties. We
review our long-lived assets to be held and used, including
proved and unproved oil and gas properties accounted for under
the successful efforts method of accounting. As a result of this
review of the recoverability of the carrying value of our
assets, we recorded an impairment of unproved oil and gas
properties of $3 million and $6.4 million in 2009 and
2008, respectively. The 2009 impairment resulted from a
write-off of $3 million in acreage costs in Northeast
British Columbia, and represents the remaining carrying value we
have recorded for the project. The 2008 impairment resulted from
a write-off of $2.3 million of drilling costs incurred for
three test wells in our Boomerang project and $4.1 related to
the drilling and completion of three wells in our Northeast
British Columbia project.
45
General and administrative. Our general and
administrative expenses, or G&A, increased
$1.7 million, or 19.5%, to $10.6 million ($1.21 per
Mcfe) for the year ended December 31, 2009 from
$8.9 million ($1.01 per Mcfe) for the year ended
December 31, 2008. Our G&A for 2009 included higher
share-based compensation, as well as higher salaries, related
employee benefit costs attributable to an increase in staff from
the prior year period and a severance payment to a former
officer. Our G&A for the year ended December 31, 2009,
also included an increase in franchise taxes. On an absolute
basis, we expect G&A to remain relatively constant in 2010.
Following is a summary of G&A (in millions and per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
% Change
|
|
|
|
$MM
|
|
|
Mcfe
|
|
|
$MM
|
|
|
Mcfe
|
|
|
$MM
|
|
|
Mcfe
|
|
|
per Mcfe
|
|
|
Salaries and benefits
|
|
$
|
4.9
|
|
|
$
|
0.56
|
|
|
$
|
4.0
|
|
|
$
|
0.45
|
|
|
$
|
0.9
|
|
|
$
|
0.11
|
|
|
|
24.4
|
%
|
Share-based compensation
|
|
|
1.8
|
|
|
|
0.21
|
|
|
|
1.1
|
|
|
|
0.13
|
|
|
|
0.7
|
|
|
|
0.08
|
|
|
|
61.5
|
|
Professional fees
|
|
|
1.4
|
|
|
|
0.16
|
|
|
|
1.4
|
|
|
|
0.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Data processing
|
|
|
0.6
|
|
|
|
0.07
|
|
|
|
0.2
|
|
|
|
0.03
|
|
|
|
0.4
|
|
|
|
0.04
|
|
|
|
133.3
|
|
Cash incentive compensation
|
|
|
0.5
|
|
|
|
0.05
|
|
|
|
1.0
|
|
|
|
0.11
|
|
|
|
(0.5
|
)
|
|
|
(0.06
|
)
|
|
|
(54.5
|
)
|
Rent expense
|
|
|
0.5
|
|
|
|
0.06
|
|
|
|
0.3
|
|
|
|
0.03
|
|
|
|
0.2
|
|
|
|
0.03
|
|
|
|
100.0
|
|
State franchise taxes
|
|
|
0.4
|
|
|
|
0.04
|
|
|
|
|
|
|
|
|
|
|
|
0.4
|
|
|
|
0.04
|
|
|
|
100.0
|
|
Other
|
|
|
0.5
|
|
|
|
0.06
|
|
|
|
0.9
|
|
|
|
0.10
|
|
|
|
(0.4
|
)
|
|
|
(0.04
|
)
|
|
|
(40.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10.6
|
|
|
$
|
1.21
|
|
|
$
|
8.9
|
|
|
$
|
1.01
|
|
|
$
|
1.7
|
|
|
$
|
0.20
|
|
|
|
19.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization. Our
depletion, depreciation and amortization expense, or DD&A,
increased $950,000, or 4%, to $24.7 million for the year
ended December 31, 2009 from $23.7 million for the
year ended December 31, 2008. Our DD&A per Mcfe
increased by $0.09, or 3.3%, to $2.80 per Mcfe for the year
ended December 31, 2009, compared to $2.71 per Mcfe for the
year ended December 31, 2008. The increase in DD&A was
primarily attributable to an increase in oil and gas property
costs, partially offset by an increase in estimated proved oil
and gas reserves.
Interest expense, net. Our interest expense
increased $518,000, or 40.8%, to $1.8 million for the year
ended December 31, 2009 from $1.3 million for the year
ended December 31, 2008. This increase was substantially
the result of our higher average debt level during 2009.
Income taxes. Our provision for income taxes
decreased to a benefit of $785,000 for the year ended
December 31, 2009, compared with expense of
$12.1 million for the year ended December 31, 2008.
Our effective income tax rate for the year ended
December 31, 2009 was 13.1%, compared with 34.1% for the
year ended December 31, 2008. The decrease in the effective
rate resulted primarily from a change in our estimated income
tax expenses for the year ended December 31, 2008, along
with an increased impact of permanent differences between book
and taxable income and increased effective state income tax
rates.
46
Years
Ended December 31, 2008 and 2007
The following table sets forth summary information regarding
natural gas, oil and NGL revenues, production, average product
prices and average production costs and expenses for the year
ended December 31, 2008 and 2007. Oil and NGLs are
converted at the rate of one Bbl equals six Mcf.
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Revenues (in thousands)
|
|
|
|
|
|
|
|
|
Gas
|
|
$
|
58,819
|
|
|
$
|
33,497
|
|
Oil
|
|
|
16,413
|
|
|
|
5,062
|
|
NGLs
|
|
|
4,637
|
|
|
|
555
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales
|
|
|
79,869
|
|
|
|
39,114
|
|
|
|
|
|
|
|
|
|
|
Realized gain on commodity derivatives
|
|
|
2,936
|
|
|
|
4,732
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales including derivative impact
|
|
$
|
82,805
|
|
|
$
|
43,846
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
Gas (MMcf)
|
|
|
7,092
|
|
|
|
4,801
|
|
Oil (MBbls)
|
|
|
175
|
|
|
|
72
|
|
NGLs (MBbls)
|
|
|
102
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
8,755
|
|
|
|
5,305
|
|
Total (MMcfe/d)
|
|
|
23.9
|
|
|
|
14.5
|
|
|
|
|
|
|
|
|
|
|
Average prices
|
|
|
|
|
|
|
|
|
Gas (per Mcf)
|
|
$
|
8.29
|
|
|
$
|
6.98
|
|
Oil (per Bbl)
|
|
|
93.79
|
|
|
|
70.31
|
|
NGLs (per Bbl)
|
|
|
45.46
|
|
|
|
46.25
|
|
|
|
|
|
|
|
|
|
|
Total (per Mcfe)
|
|
$
|
9.12
|
|
|
$
|
7.37
|
|
|
|
|
|
|
|
|
|
|
Realized gain on commodity derivatives (per Mcfe)
|
|
|
0.34
|
|
|
|
0.89
|
|
|
|
|
|
|
|
|
|
|
Total including derivative impact (per Mcfe)
|
|
$
|
9.46
|
|
|
$
|
8.26
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses (per Mcfe)
|
|
|
|
|
|
|
|
|
Lease operating(1)
|
|
$
|
0.87
|
|
|
$
|
0.72
|
|
Severance and production taxes
|
|
|
0.48
|
|
|
|
0.31
|
|
Exploration
|
|
|
0.17
|
|
|
|
0.17
|
|
Impairment of unproved properties
|
|
|
0.73
|
|
|
|
0.05
|
|
General and administrative
|
|
|
1.01
|
|
|
|
2.39
|
|
Depletion, depreciation and amortization
|
|
|
2.71
|
|
|
|
2.47
|
|
|
|
|
(1) |
|
Lease operating expenses per Mcfe includes ad valorem taxes. |
Oil and gas production. Production for the
year ended December 31, 2008 totaled 8.7 Bcfe
(23.9 MMcfe/d), compared to 5.3 Bcfe
(14.5 MMcfe/d) produced in the prior year, an increase of
65%. Production for the year ended December 31, 2008 was
81% natural gas and 19% oil and NGLs, compared to 90% natural
gas and 10% oil and NGLs in prior year period.
Oil and gas sales. Oil and gas sales increased
$40.8 million, or 104.2%, for the year ended
December 31, 2008 to $79.9 million from
$39.1 million for the year ended December 31, 2007.
The increase in oil and gas sales principally resulted from our
increased ownership in the Ozona Northeast field as a result of
our acquisition of the Neo Canyon interest in the fourth quarter
of 2007 and increased revenue from our Cinco Terry and North
Bald Prairie fields. We now own substantially all working
interests in Ozona Northeast. Of the 8,755 MMcfe of
production reported for 2008, approximately 1,791 MMcfe was
attributable to the interest acquired from Neo Canyon. The
increase in oil and gas sales also resulted from continued
development of our Cinco Terry and North Bald Prairie fields.
Cinco Terry production increased by 2,097 MMcfe compared to
the prior year. Production from North Bald Prairie accounted for
447 MMcfe in
47
production for 2008. Further, the average price per Mcfe we
received for our production increased from $7.37 to $9.12 per
Mcfe as average oil and gas prices increased significantly
between the two years. Of the $40.8 million increase in
revenues, $32.8 million was attributable to growth in
volume with the remaining $8 million due to oil and gas
price increases. Natural gas sales represented 73.6% of the
total oil and gas sales in 2008 compared to 85.6% in 2007, as
our Cinco Terry field has a larger component of oil and NGLs in
its production.
Commodity derivative activities. Realized
losses and gains from our commodity derivative activity
increased our earnings by $2.9 million and
$4.7 million for the years ended December 31, 2008 and
2007, respectively. Realized gains and losses are derived from
the relative movement of gas prices in relation to the range of
prices in our collars or the fixed notional pricing for the
respective years. The unrealized gain on commodity derivatives
was $7.1 million for 2008 and the unrealized loss on
commodity derivatives was $3.6 million for 2007. As natural
gas commodity prices increase, the fair value of the open
portion of those positions decreases. As natural gas commodity
prices decrease, the fair value of the open portion of those
positions increases. Historically, we have not designated our
derivative instruments as cash-flow hedges. We record our open
derivative instruments at fair value on our consolidated balance
sheets as either unrealized gains or losses on commodity
derivatives. We record changes in such fair value in earnings on
our consolidated statements of operations under the caption
entitled unrealized (loss) gain on commodity
derivatives.
Lease operating expense. Our LOE increased
$3.8 million, or 99.8%, for the year ended
December 31, 2008 to $7.6 million ($0.87 per Mcfe)
from $3.8 million ($0.72 per Mcfe) for the year ended
December 31, 2007. The increase in LOE over the prior year
was primarily a result of the acquisition of the Neo Canyon 30%
working interest and Strawn/Ellenburger deep rights in Ozona
Northeast. The increase in 2008 was also attributable to initial
startup costs, including compression and treating costs in Cinco
Terry and North Bald Prairie, as well as a rise in repair and
maintenance costs in Ozona Northeast. Following is a summary of
lease operating expenses (per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
% Change
|
|
|
Compressor rental and repair
|
|
$
|
0.28
|
|
|
$
|
0.18
|
|
|
$
|
0.10
|
|
|
|
55.6
|
%
|
Pumpers and supervision
|
|
|
0.15
|
|
|
|
0.10
|
|
|
|
0.05
|
|
|
|
50.0
|
|
Ad valorem taxes
|
|
|
0.14
|
|
|
|
0.18
|
|
|
|
(0.04
|
)
|
|
|
(22.2
|
)
|
Repairs and maintenance
|
|
|
0.13
|
|
|
|
0.07
|
|
|
|
0.06
|
|
|
|
85.7
|
|
Water hauling, insurance and other
|
|
|
0.13
|
|
|
|
0.12
|
|
|
|
0.01
|
|
|
|
8.3
|
|
Workovers
|
|
|
0.04
|
|
|
|
0.07
|
|
|
|
(0.03
|
)
|
|
|
(42.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
0.87
|
|
|
$
|
0.72
|
|
|
$
|
0.15
|
|
|
|
20.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and production taxes. Our production
taxes increased $2.5 million, or 153.3%, for the year ended
December 31, 2008 to $4.2 million from
$1.7 million for the year ended December 31, 2007. The
increase in production taxes was a function of the increase in
oil and gas sales between the two periods. Severance and
productions taxes amounted to approximately 5.3% and 4.2% of oil
and gas sales for the respective years. The increase in the
severance and production taxes as a percentage of oil and gas
sales is due to higher severance tax rates for NGL revenues from
Cinco Terry and higher estimated taxes after abatements for
newer wells in Ozona Northeast and Cinco Terry.
Exploration. We recorded $1.5 million of
exploration expense for the year ended December 31, 2008,
compared to $883,000 for the year ended December 31, 2007.
Exploration expense for the 2008 period resulted from one dry
hole drilled in Ozona Northeast and $965,000 of lease extensions
in Ozona Northeast. We incur these costs to maintain our
leasehold positions and accordingly, we expense them as
incurred. Exploration expense for the 2007 period resulted from
the drilling of two dry holes in our Boomerang project and Cinco
Terry project.
Impairment of oil and gas properties. We
review our long-lived assets to be held and used, including
proved and unproved oil and gas properties accounted for under
the successful efforts method of accounting.
48
As a result of this review of the recoverability of the carrying
value of our assets, we recorded an impairment of oil and gas
properties of $6.4 million and $267,000 in 2008 and 2007,
respectively. The 2008 impairment resulted from a write-off of
$2.3 million of drilling costs incurred for three test
wells in our Boomerang project and $4.1 related to the drilling
and completion of three wells in our Northeast British Columbia
project. The 2007 impairment resulted from the abandonment of an
expiring leasehold position in Ozona Northeast covering
2,282 acres.
General and administrative. Our G&A
decreased $3.8 million, or 29.9%, to $8.9 million
($1.01 per Mcfe) for the year ended December 31, 2008 from
$12.7 million ($2.39 per Mcfe) for the year ended
December 31, 2007. Our G&A for 2007 included
$4.6 million in non-cash, share-based compensation (of
which $3.9 million was related to the IPO),
$2.4 million in cash incentive compensation to cover
out-of-pocket
taxes related to IPO stock awards, $1 million of cash
incentive compensation related to the IPO and $0.7 million
in cash incentive compensation to cover
out-of-pocket
taxes related to managements exchange of common stock in
2007 to repay full recourse management notes before the IPO.
Partially offsetting the higher expenses in 2007 was an increase
in G&A in 2008 attributable to increased salaries and
benefits of $2 million related to an increase in staff,
professional fees of $900,000, share-based compensation of
$1.1 million and cash incentive compensation of $967,000.
Additionally, the 2007 period includes a severance obligation of
$350,000 related to a former employee. Following is a summary of
G&A (in millions and per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
% Change
|
|
|
|
$MM
|
|
|
Mcfe
|
|
|
$MM
|
|
|
per Mcfe
|
|
|
$MM
|
|
|
Mcfe
|
|
|
per Mcfe
|
|
|
Salaries and benefits
|
|
$
|
4.0
|
|
|
$
|
0.45
|
|
|
$
|
2.8
|
|
|
$
|
0.54
|
|
|
$
|
1.2
|
|
|
$
|
(0.09
|
)
|
|
|
(16.7
|
)%
|
Professional fees
|
|
|
1.4
|
|
|
|
0.16
|
|
|
|
0.5
|
|
|
|
0.10
|
|
|
|
0.9
|
|
|
|
0.06
|
|
|
|
60.0
|
|
Share-based compensation
|
|
|
1.1
|
|
|
|
0.13
|
|
|
|
4.6
|
|
|
|
0.87
|
|
|
|
(3.5
|
)
|
|
|
(0.74
|
)
|
|
|
(85.1
|
)
|
Cash incentive compensation
|
|
|
1.0
|
|
|
|
0.11
|
|
|
|
4.1
|
|
|
|
0.77
|
|
|
|
(3.1
|
)
|
|
|
(0.66
|
)
|
|
|
(85.7
|
)
|
Other
|
|
|
1.4
|
|
|
|
0.16
|
|
|
|
0.7
|
|
|
|
0.11
|
|
|
|
0.7
|
|
|
|
0.05
|
|
|
|
45.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
8.9
|
|
|
$
|
1.01
|
|
|
$
|
12.7
|
|
|
$
|
2.39
|
|
|
$
|
(3.8
|
)
|
|
$
|
(1.38
|
)
|
|
|
(57.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization. Our
DD&A increased $10.6 million, or 81%, to
$23.7 million for the year ended December 31, 2008
from $13.1 million for the year ended December 31,
2007. Our DD&A per Mcfe increased by $0.24, or 9.7%, to
$2.71 per Mcfe for the year ended December 31, 2008,
compared to $2.47 per Mcfe for the year ended December 31,
2007. The increase in DD&A was primarily attributable to
increased production and higher capital costs, partially offset
by an increase in our estimated proved reserves at
December 31, 2008. The higher DD&A per Mcfe was
primarily attributable to higher capital costs incurred in North
Bald Prairie and reserve revisions in Ozona Northeast at
December 31, 2007. In North Bald Prairie, we paid capital
costs attributable to the 50% working interest owned by our
working interest partner pursuant to our carry and earning
agreement on the first five wells drilled.
Interest expense, net. Our interest expense
decreased $4 million, or 75.7%, to $1.3 million for
the year ended December 31, 2008 from $5.2 million for
the year ended December 31, 2007. This decrease was
substantially the result of our lower average debt level and
lower interest rates in 2008. Additionally, interest expense for
the year ended December 31, 2007 included $1.5 million
related to the beneficial conversion feature of our convertible
notes and $548,000 relating to accrued interest on the
convertible notes.
Income taxes. Our provision for income taxes
increased to $12.1 million for the year ended
December 31, 2008, from a benefit of $108,000 for the year
ended December 31, 2007. The increase in income tax expense
was due to the increase in our income before income taxes. Our
effective income tax rate for the year ended December 31,
2008 was 34.1%, compared with a benefit of 4.2% for the year
ended December 31, 2007. The tax benefit for the year ended
December 31, 2007 related to the release of a valuation
allowance on net operating loss carryovers generated by AOG
before the combination of AOG and Approach under the
Contribution Agreement on November 14, 2007.
49
Liquidity
and Capital Resources
We generally will rely on cash generated from operations,
borrowings under our revolving credit facility and, to the
extent that credit and capital market conditions will allow,
future public equity and debt offerings to satisfy our liquidity
needs. Our ability to fund planned capital expenditures and to
make acquisitions depends upon our future operating performance,
availability of borrowings under our revolving credit facility,
and more broadly, on the availability of equity and debt
financing, which is affected by prevailing economic conditions
in our industry and financial, business and other factors, some
of which are beyond our control. We cannot predict whether
additional liquidity from equity or debt financings beyond our
revolving credit facility will be available on acceptable terms,
or at all, in the foreseeable future.
Our cash flow from operations is driven by commodity prices and
production volumes and the effect of commodity derivatives.
Prices for oil and gas are affected by national and
international economic and political environments, national and
global supply and demand for hydrocarbons, seasonal influences
of weather and other factors beyond our control. Our working
capital is significantly influenced by changes in commodity
prices, and significant declines in prices will cause a decrease
in our production volumes and exploration and development
expenditures. Our working capital also is influenced by our
efforts to lower our long-term debt and related interest costs.
Cash flows from operations are primarily used to fund
exploration and development of our oil and gas properties.
We intend to fund 2010 capital expenditures, excluding any
acquisitions, primarily out of internally-generated cash flows
and, as necessary, borrowings under our revolving credit
facility. As of December 31, 2009, we had
$82.3 million available to borrow under our revolving
credit facility.
For the year ended December 31, 2009, our primary sources
of cash were from operating activities. Approximately
$39.8 million of cash from operations was used to fund our
drilling program and
3-D seismic
operations and pay down our long-term debt.
For the year ended December 31, 2008, our primary sources
of cash were from financing and operating activities.
Approximately $43.5 million from borrowings (net of
payments) under our revolving credit facility and $56.4 million
cash from operations were used to fund our drilling program and
the acquisition of a 95% working interest below the top of the
Strawn formation and rights to 75 miles of gathering system
in the Ozona Northeast field.
Our primary sources of cash in 2007 were from financing and
operating activities. Approximately $64.3 million from
borrowings under our revolving credit facility,
$72.4 million from the issuance of common stock,
$20 million from proceeds from convertible notes and
$30.7 million cash from operations were used to fund our
drilling activities, repay our revolving credit facility and
purchase 2,021,148 shares of our common stock from the
selling stockholder in our IPO.
In comparing 2009 and 2008, our cash flows from operations
decreased in 2009 due mostly to lower oil and gas sales
partially offset by an increase in other cash income and expense
items and a decrease in working capital components during the
year ended December 31, 2009. In comparing 2008 and 2007,
our cash flows from operations increased in 2008 due mostly to
higher oil and gas sales partially offset by an increase in most
operating expense categories and a decrease in working capital
components during the year ended December 31, 2008.
50
The following table summarizes our sources and uses of funds for
the periods noted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Cash flows provided by operating activities
|
|
$
|
39,761
|
|
|
$
|
56,435
|
|
|
$
|
30,746
|
|
Cash flows used in investing activities
|
|
|
(29,553
|
)
|
|
|
(100,633
|
)
|
|
|
(52,940
|
)
|
Cash flows (used in) provided by financing activities
|
|
|
(11,618
|
)
|
|
|
43,696
|
|
|
|
22,062
|
|
Effect of Canadian exchange rate
|
|
|
18
|
|
|
|
(206
|
)
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
$
|
(1,392
|
)
|
|
$
|
(708
|
)
|
|
$
|
(126
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Despite the adverse price environment in 2009, we were able to
pay down our long-term debt and increase our liquidity by over
40%, from $60.5 million at December 31, 2008 to
$85.4 million at December 31, 2009. We define
liquidity as funds available under our credit facility plus
year-end cash and cash equivalents. At December 31, 2009,
we had $32.3 million in long-term debt outstanding under
our revolving credit facility, compared to $43.5 million in
long-term debt outstanding at December 31, 2008. The
following table summarizes our liquidity position at
December 31, 2009 compared to December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Borrowing base
|
|
$
|
115,000
|
|
|
$
|
100,000
|
|
Cash and cash equivalents
|
|
|
2,685
|
|
|
|
4,077
|
|
Long-term debt
|
|
|
(32,319
|
)
|
|
|
(43,537
|
)
|
|
|
|
|
|
|
|
|
|
Liquidity
|
|
$
|
85,366
|
|
|
$
|
60,540
|
|
|
|
|
|
|
|
|
|
|
Operating
Activities
For the year ended December 31, 2009, our cash flow from
operations, borrowings under our revolving credit facility and
available cash were used for drilling activities,
3-D seismic
operations and for the payment of a portion of our long-term
debt. The $39.8 million in cash flows generated in the 2009
period decreased $16.7 million from the same period in 2008
due primarily to a $39.2 million decline in oil and gas
sales, partially offset by a $10 million decrease in
working capital components and a net increase of
$12.5 million in other cash income and expense items.
For the year ended December 31, 2008, our cash flow from
operations, borrowings under our revolving credit facility and
available cash were used for drilling activities. The
$56.4 million in cash flow generated during 2008 period
increased by $25.7 million from 2007 due primarily to an
increase in oil and gas sales and a decrease in general and
administrative expenses. Partially offsetting the increase in
oil and gas sales and decrease in general administrative
expenses was a reduction in working capital and an increase in
LOE and production taxes in the 2008 period compared to the 2007
period.
For the year ended December 31, 2007, our cash flow from
operations was used for drilling activities. The
$30.7 million in cash flow generated during 2007 decreased
$3.6 million from 2006 due mostly to lower oil and gas
sales and higher general and administrative expenses in the 2007
period.
51
Investing
Activities
The majority of our cash flows used in investing activities for
the years ended 2009, 2008 and 2007 have been used for the
continued development of the Ozona Northeast, Cinco Terry and
North Bald Prairie fields. The following is a summary of capital
expenditures related to our oil and gas properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Ozona Northeast
|
|
$
|
5,768
|
|
|
$
|
31,362
|
|
|
$
|
27,986
|
|
Ozona Northeast deep rights acquisition
|
|
|
|
|
|
|
10,346
|
|
|
|
|
|
Cinco Terry
|
|
|
20,630
|
|
|
|
32,363
|
|
|
|
10,586
|
|
North Bald Prairie
|
|
|
1,554
|
|
|
|
15,871
|
|
|
|
4,974
|
|
El Vado East
|
|
|
151
|
|
|
|
176
|
|
|
|
|
|
Boomerang
|
|
|
|
|
|
|
290
|
|
|
|
2,496
|
|
Inventory
|
|
|
(1,959
|
)
|
|
|
2,365
|
|
|
|
|
|
Northeast British Columbia
|
|
|
86
|
|
|
|
2,993
|
|
|
|
1,235
|
|
Lease acquisition, geological, geophysical and other
|
|
|
2,760
|
|
|
|
4,323
|
|
|
|
4,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
28,990
|
|
|
$
|
100,089
|
|
|
$
|
52,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease acquisition, geological, geophysical and other for the
year ended December 31, 2009 includes:
|
|
|
|
|
$1.1 million of leasehold acquisitions related to Cinco
Terry;
|
|
|
|
$915,000 of
3-D seismic
acquisition related to Cinco Terry; and
|
|
|
|
$500,000 of leasehold acquisitions related to North Bald Prairie
during the year ended December 31, 2009.
|
Lease acquisition, geological, geophysical and other for the
year ended December 31, 2008 includes:
|
|
|
|
|
$1.9 million of leasehold acquisitions related to Ozona
Northeast; and
|
|
|
|
$2 million of leasehold acquisitions related to Cinco Terry
during the year ended December 31, 2008.
|
Lease acquisition, geological, geophysical and other for the
year ended December 31, 2007 includes:
|
|
|
|
|
$3 million for undeveloped leaseholds in our Northeast
British Columbia prospect; and
|
|
|
|
$2.5 million for undeveloped leaseholds in our El Vado East
prospect during the year ended December 31, 2007.
|
Financing
Activities
We borrowed $67.4 million under our revolving credit
facility in 2009 compared to $121.7 million in 2008 and
$64.3 million in 2007. We repaid a total of
$78.6 million, $78.2 million and $111.9 million
of amounts outstanding under our revolving credit facility for
the years ended December 31, 2009, 2008 and 2007,
respectively. In 2007, we borrowed $20 million by issuing
convertible notes. These notes were converted to outstanding
shares of our common stock in connection with our IPO in
November 2007.
In 2007, and in connection with our IPO and exercise by the
underwriters of their overallotment option, we sold
6,598,572 shares of our common stock in November 2007 at
$12 per share. The gross proceeds of our IPO and over-allotment
option were approximately $79.2 million, which resulted in
net proceeds to the Company of $73.6 million after
deducting underwriter discounts and commissions of approximately
$5.6 million. The aggregate net proceeds of approximately
$73.6 million received by the Company were used as follows
(in millions):
|
|
|
|
|
Repayment of revolving credit facility
|
|
$
|
51.1
|
|
Repurchase of stock held by selling stockholder
|
|
$
|
22.5
|
|
52
Our current goal is to manage our borrowings to help us maintain
financial flexibility and liquidity, and to avoid the problems
associated with highly-leveraged companies with large interest
costs and possible debt reductions restricting ongoing
operations.
We believe that cash flows from operations and borrowings under
our revolving credit facility will finance substantially all of
our capital needs through 2010. We may also use our revolving
credit facility for possible acquisitions and temporary working
capital needs. Further, we may determine to access the public
equity or debt markets for potential acquisitions, working
capital or other liquidity needs, if such financing is available
on acceptable terms. In January 2010, we filed a
shelf registration statement on
Form S-3
registering up to $150 million of common stock, debt and
other securities. The registration statement was declared
effective by the SEC on February 1, 2010.
2010
Capital Expenditures
The following table summarizes our estimated capital
expenditures for 2010. We intend to fund 2010 capital
expenditures, excluding any acquisitions, primarily out of
internally-generated cash flows and, as necessary, borrowings
under our revolving credit facility.
|
|
|
|
|
|
|
Year Ending
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
West Texas
|
|
|
|
|
Ozona Northeast
|
|
$
|
25,600
|
|
Cinco Terry
|
|
|
19,950
|
|
Exploratory
|
|
|
3,075
|
|
Lease acquisition, geological and geophysical
|
|
|
4,375
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
53,000
|
|
|
|
|
|
|
Our capital expenditure budget for 2010 is subject to change
depending upon a number of factors, including economic and
industry conditions at the time of drilling, prevailing and
anticipated prices for oil and gas, the results of our
development and exploration efforts, the availability of
sufficient capital resources for drilling prospects, our
financial results, the availability of leases on reasonable
terms and our ability to obtain permits for the drilling
locations. We expect drilling rigs, drilling crews, steel
tubulars and oilfield services to be in high demand in the
Permian Basin during 2010, and that the costs related to these
services will increase from 2009 levels.
Revolving
Credit Facility
We have a $200 million revolving credit facility with a
borrowing base set at $115 million. The borrowing base is
redetermined semi-annually on or before each April 1 and October
1 based on our oil and gas reserves. We or the lenders can each
request one additional borrowing base redetermination each
calendar year.
Currently, the maturity date under our revolving credit facility
is July 31, 2011. Borrowings bear interest based on the
agent banks prime rate plus an applicable margin ranging
from 1.25% to 2.25%, or the sum of the Eurodollar rate plus an
applicable margin ranging from 2.25% to 3.25%. Margins vary
based on the borrowings outstanding compared to the borrowing
base. In addition, we pay an annual commitment of 0.50% of
non-used borrowings available under our revolving credit
facility.
We had outstanding borrowings of $32.3 million under our
revolving credit facility at December 31, 2009. The
weighted average interest rate applicable to our outstanding
borrowings was 3.20% at December 31, 2009. We also had
outstanding unused letters of credit under our revolving credit
facility totaling $400,000 at December 31, 2009, which
reduce amounts available for borrowing under our revolving
credit facility.
53
Loans under our revolving credit facility are secured by first
priority liens on substantially all of our West Texas assets and
are guaranteed by our subsidiaries.
At February 28, 2010, we had $37.9 million outstanding
under our revolving credit facility, with a weighted average
interest rate of 3.42%.
Covenants
Our credit agreement contains two principal financial covenants:
|
|
|
|
|
a consolidated modified current ratio covenant that requires us
to maintain a ratio of not less than 1.0 to 1.0 at all times.
The consolidated modified current ratio is calculated by
dividing Consolidated Current Assets (as defined in the credit
agreement) by Consolidated Current Liabilities (as defined in
the credit agreement). As defined more specifically in the
credit agreement, the consolidated modified current ratio is
calculated as current assets less current unrealized gains on
commodity derivatives plus the available borrowing base at the
respective balance sheet date, divided by current liabilities
less current unrealized losses on commodity derivatives at the
respective balance sheet date.
|
|
|
|
a consolidated funded debt to consolidated EBITDAX ratio
covenant that requires us to maintain a ratio of not more than
3.5 to 1.0 at the end of each fiscal quarter. The consolidated
funded debt to consolidated EBITDAX ratio is calculated by
dividing Consolidated Funded Debt (as defined in the credit
agreement) by Consolidated EBITDAX (as defined in the credit
agreement). As defined more specifically in the credit
agreement, consolidated EBITDAX is calculated as net income
(loss), plus (1) exploration expense, (2) depletion,
depreciation and amortization expense, (3) share-based
compensation expense, (4) unrealized loss on commodity
derivatives, (5) interest expense, (6) income and
franchise taxes and (7) certain other non-cash expenses,
less (1) gains or losses from sales or dispositions of
assets, (2) unrealized gain on commodity derivatives and
(3) extraordinary or non-recurring gains. For purposes of
calculating this ratio, consolidated EBITDAX for a fiscal
quarter is annualized pursuant to the credit agreement.
|
Our credit agreement also restricts cash dividends and other
restricted payments, transactions with affiliates, incurrence of
other debt, consolidations and mergers, the level of operating
leases, assets sales, investments in other entities and liens on
properties.
In addition, our credit agreement contains customary events of
default that would permit our lenders to accelerate the debt
under our credit agreement if not cured within applicable grace
periods, including, among others, failure to make payments of
principal or interest when due, materially incorrect
representations and warranties, failure to make mandatory
prepayments in the event of borrowing base deficiencies, breach
of covenants, defaults upon other obligations in excess of
$500,000, events of bankruptcy, the occurrence of one or more
unstayed judgments in excess of $500,000 not covered by an
acceptable policy of insurance, failure to pay any obligation in
excess of $500,000 owed under any derivatives transaction or in
any amount if the obligation under the derivatives transaction
is secured by collateral under the credit agreement, any event
of default by the Company occurs under any agreement entered
into in connection with a derivatives transaction, liens
securing the loans under the credit agreement cease to be in
place, a Change in Control (as more specifically defined in the
credit agreement) of the Company occurs, and dissolution of the
Company.
At December 31, 2009, we were in compliance with all of our
covenants and had not committed any acts of default under the
credit agreement.
To date we have experienced no disruptions in our ability to
access our revolving credit facility. However, our lenders have
substantial ability to reduce our borrowing base on the basis of
subjective factors, including the loan collateral value that
each lender, in its discretion and using the methodology,
assumptions and discount rates as such lender customarily uses
in evaluating oil and gas properties, assigns to our properties.
54
Contractual
Commitments
Our contractual commitments consist of long-term debt, accrued
interest on long-term debt, daywork drilling contracts,
operating lease obligations, asset retirement obligations and
employment agreements with executive officers.
Our long-term debt is composed of borrowings under our revolving
credit facility. Borrowings based on the agent banks prime
rate plus an applicable margin ranging from 1.25% to 2.25%, or
the sum of the Eurodollar rate plus an applicable margin ranging
from 2.25% to 3.25%. Margins vary based on the borrowings
outstanding compared to the borrowing base. In addition, we pay
an annual commitment of 0.50% of non-used borrowings available
under our revolving credit facility. See Managements
Discussion and Analysis of Financial Condition and Results of
Operations Credit Facility and Note 4 for
a discussion of our revolving credit facility.
We periodically enter into contractual arrangements under which
we are committed to expend funds to drill wells in the future,
including agreements to secure drilling rig services, which
require us to make future minimum payments to the rig operators.
We record drilling commitments in the periods in which well
capital expenditures are incurred or rig services are provided.
Our commitment under the drilling contracts is $1.2 million
at December 31, 2009.
In April 2007, we signed a five-year lease for approximately
13,000 square feet of office space in Fort Worth,
Texas. In August 2008, we expanded our office space under an
amendment to the lease to approximately 18,000 square feet.
In January 2009, we began rent payments of approximately $30,000
per month, including common area expenses.
Our asset retirement obligation primarily represents the
estimated present value of the amount we will incur to plug,
abandon and remediate our producing properties at the end of
their productive lives, in accordance with applicable federal,
state and local laws. We determine our asset retirement
obligation by calculating the present value of estimated cash
flows related to the liability. The retirement obligation is
recorded as a liability at its estimated present value as of the
assets inception, with an offsetting increase to proved
properties. Periodic accretion of discount of the estimated
liability is recorded as an expense in the income statement.
We have outstanding employment agreements with two of our
executive officers that contain automatic renewal provisions
providing that such agreements may be automatically renewed for
successive terms of one year unless employment is terminated at
the end of the term by written notice given to the employee not
less than 60 days prior to the end of such term. Our
maximum commitment under the employment agreements, which would
apply if the employees covered by these agreements were all
terminated without cause, was approximately $700,000 at
December 31, 2009.
55
The following table summarizes these commitments as of
December 31, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less than
|
|
|
|
|
|
|
|
|
More than
|
|
Contractual Obligations
|
|
Total
|
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
Long-term debt(1)
|
|
$
|
32,319
|
|
|
$
|
|
|
|
$
|
32,319
|
|
|
$
|
|
|
|
$
|
|
|
Interest on long-term debt(2)
|
|
|
1,637
|
|
|
|
1,034
|
|
|
|
603
|
|
|
|
|
|
|
|
|
|
Daywork drilling contracts(3)
|
|
|
1,169
|
|
|
|
1,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating lease obligations(4)
|
|
|
1,182
|
|
|
|
410
|
|
|
|
772
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations(5)
|
|
|
4,597
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,597
|
|
Employment agreements with executive officers
|
|
|
700
|
|
|
|
700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
41,604
|
|
|
$
|
3,313
|
|
|
$
|
33,694
|
|
|
$
|
|
|
|
$
|
4,597
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
See Note 4 to our consolidated financial statements for a
discussion of our revolving credit facility. |
|
(2) |
|
Interest payments have been calculated by applying the interest
rate of 3.20% at December 31, 2009, to the outstanding
long-term debt of $32.3 million at December 31, 2009. |
|
(3) |
|
Daywork drilling contracts related to three drilling rigs
contracted through February 28, 2010. |
|
(4) |
|
Operating lease obligations are for office space and equipment. |
|
(5) |
|
See Note 1 to our consolidated financial statements for a
discussion of our asset retirement obligations. |
Off-Balance
Sheet Arrangements
From time to time, we enter into off-balance sheet arrangements
and transactions that can give rise to off-balance sheet
obligations. As of December 31, 2009, the off-balance sheet
arrangements and transactions that we have entered into include
undrawn letters of credit, operating lease agreements and gas
transportation commitments. We do not believe that these
arrangements are reasonably likely to materially affect our
liquidity or availability of, or requirements for, capital
resources.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk.
|
Some of the information below contains forward-looking
statements. The primary objective of the following information
is to provide forward-looking quantitative and qualitative
information about our potential exposure to market risks. The
term market risk refers to the risk of loss arising
from adverse changes in oil and gas prices, and other related
factors. The disclosure is not meant to be a precise indicator
of expected future losses, but rather an indicator of reasonably
possible losses. This forward-looking information provides an
indicator of how we view and manage our ongoing market risk
exposures. Our market risk sensitive instruments were entered
into for commodity derivative and investment purposes, not for
trading purposes.
Proved
Reserves
Estimates of proved oil and gas reserves directly impact
financial accounting estimates including depletion, depreciation
and amortization expense, evaluation of impairment of properties
and the calculation of plugging and abandonment liabilities.
Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically
producible from a given date forward, from known
reservoirs, and under existing economic conditions, operating
methods, and government regulations The process of estimating
quantities of proved reserves is very complex, requiring
significant subjective decisions in the evaluation of all
geological, engineering and economic data for each reservoir.
The data for any reservoir may change substantially over time
due to results from operational activity. Proved reserve volumes
at December 31, 2009, were estimated based on the
unweighted, arithmetic average of the closing price on the first
day of each month for the
12-month
period prior to December 31, 2009 for natural gas, oil and
NGLs, in accordance with new reserve rules.
56
Changes in commodity prices and operation costs may also affect
the overall evaluation of reservoirs. A hypothetical 10% decline
in our December 31, 2009 estimated proved reserves would
have increased our depletion expense by approximately $625,000
for the year ended December 31, 2009. Under previous
reserve rules (year-end 2009 spot prices for natural gas, oil
and NGLs), our depletion expense would have decreased by
approximately $400,000.
Commodity
Price Risk
Given the current economic outlook, we expect commodity prices
to remain volatile. Even modest decreases in commodity prices
can materially affect our revenues and cash flow. In addition,
if commodity prices remain suppressed for a significant amount
of time, we could be required under successful efforts
accounting rules to perform a write down of our oil and gas
properties.
We enter into financial swaps and collars to reduce the risk of
commodity price fluctuations. We do not designate such
instruments as cash flow hedges. Accordingly, we record open
commodity derivative positions on our consolidated balance
sheets at fair value and recognize changes in such fair values
as income (expense) on our consolidated statements of operations
as they occur.
At December 31, 2009, we have the following commodity
derivative positions outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
$/MMBtu
|
Period
|
|
Monthly
|
|
Total
|
|
Fixed
|
|
NYMEX Henry Hub
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swaps 2010
|
|
|
150,000
|
|
|
|
1,800,000
|
|
|
$
|
5.85
|
|
Price swaps 2010
|
|
|
150,000
|
|
|
|
1,800,000
|
|
|
$
|
6.40
|
|
Price swaps 2010
|
|
|
100,000
|
|
|
|
1,200,000
|
|
|
$
|
6.36
|
|
WAHA basis differential
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps 2010
|
|
|
415,000
|
|
|
|
4,980,000
|
|
|
$
|
(0.71
|
)
|
Basis swaps 2011
|
|
|
300,000
|
|
|
|
3,600,000
|
|
|
$
|
(0.53
|
)
|
At December 31, 2009 and December 31, 2008, the fair
value of our open derivative contracts was a net liability of
approximately $1.9 million and an asset of $8 million,
respectively.
JPMorgan Chase Bank, National Association and KeyBank National
Association are currently the only counterparties to our
commodity derivatives positions. We are exposed to credit losses
in the event of nonperformance by counterparties on our
commodity derivatives positions. However, we do not anticipate
nonperformance by the counterparties over the term of the
commodity derivatives positions. JPMorgan is the administrative
agent and a participant, and KeyBank is a participant, in our
revolving credit facility and the collateral for the outstanding
borrowings under our revolving credit facility is used as
collateral for our commodity derivatives.
Unrealized gains and losses, at fair value, are included on our
consolidated balance sheets as current or non-current assets or
liabilities based on the anticipated timing of cash settlements
under the related contracts. Changes in the fair value of our
commodity derivative contracts are recorded in earnings as they
occur and included in other income (expense) on our consolidated
statements of operations. We estimate the fair values of swap
contracts based on the present value of the difference in
exchange-quoted forward price curves and contractual settlement
prices multiplied by notional quantities. We internally valued
the collar contracts using industry-standard option pricing
models and observable market inputs. We use our internal
valuations to determine the fair values of the contracts that
are reflected on our consolidated balance sheets. Realized gains
and losses are also included in other income (expense) on our
consolidated statements of operations.
For the years ended December 31, 2009 and 2007, we
recognized an unrealized loss of $9.9 million and
$3.6 million, respectively, from the change in the fair
value of commodity derivatives. For the year ended
December 31, 2008, we recognized an unrealized gain of
$7.1 million from the change in the fair value of commodity
derivatives. For the year ended December 31, 2009, the
unrealized loss on commodity derivatives was primarily
attributable to the settlement of derivative contracts. A
hypothetical 10% increase in the
57
NYMEX floating prices would have resulted in a $2.7 million
decrease in the December 31, 2009 fair value recorded on
our balance sheet, and a corresponding increase to the loss on
commodity derivatives in our statement of operations.
To estimate the fair value of our commodity derivatives
positions, we use market data or assumptions that market
participants would use in pricing the asset or liability,
including assumptions about risk and the risks inherent in the
inputs to the valuation technique. These inputs can be readily
observable, market corroborated or generally unobservable. We
primarily apply the market approach for recurring fair value
measurements and attempt to use the best available information.
We determine the fair value based upon the hierarchy that
prioritizes the inputs used to measure fair value. The hierarchy
gives the highest priority to unadjusted quoted prices in active
markets for identical assets or liabilities (Level 1
measurement) and lowest priority to unobservable inputs
(Level 3 measurement). The three levels of fair value
hierarchy are as follows:
|
|
|
|
|
Level 1 Quoted prices are available in active
markets for identical assets or liabilities as of the reporting
date. At December 31, 2009, we had no Level 1
measurements.
|
|
|
|
Level 2 Pricing inputs are other than quoted
prices in active markets included in Level 1, which are
either directly or indirectly observable as of the reporting
date. Level 2 includes those financial instruments that are
valued using models or other valuation methodologies. These
models are primarily industry-standard models that consider
various assumptions, including quoted forward prices for
commodities, time value, volatility factors and current market
and contractual prices for the underlying instruments, as well
as other relevant economic measures. Our derivatives, which
consist primarily of commodity swaps and collars, are valued
using commodity market data which is derived by combining raw
inputs and quantitative models and processes to generate forward
curves. Where observable inputs are available, directly or
indirectly, for substantially the full term of the asset or
liability, the instrument is categorized in Level 2. At
December 31, 2009, all of our commodity derivatives were
valued using Level 2 measurements.
|
|
|
|
Level 3 Pricing inputs include significant
inputs that are generally less observable from objective
sources. These inputs may be used with internally developed
methodologies that result in managements best estimate of
fair value. At December 31, 2009, our Level 3
measurements were used to calculate our asset retirement
obligation and our impairment analysis of proved properties at
December 31, 2009.
|
|
|
Item 8.
|
Financial
Statements and Supplementary Data.
|
See Index to Financial Statements on
page F-1
of this report.
58
|
|
Item 9.
|
Changes
in and Disagreements With Accountants on Accounting and
Financial Disclosure.
|
None.
|
|
Item 9A.
|
Controls
and Procedures.
|
Disclosure
Controls and Procedures
Our management, with the participation of our President and
Chief Executive Officer and Chief Financial Officer, has
evaluated the effectiveness of our disclosure controls and
procedures (as defined in
Rules 13a-15(e)
and
15d-15(e)
under the Exchange Act) as of December 31, 2009. Based on
this evaluation, our President and Chief Executive Officer and
Chief Financial Officer have concluded that, as of
December 31, 2009, our disclosure controls and procedures
were effective, in that they ensure that information required to
be disclosed by us in the reports that we file or submit under
the Exchange Act is (1) recorded, processed, summarized and
reported within the time periods specified in the SECs
rules and forms, and (2) accumulated and communicated to
our management, including our President and Chief Executive
Officer and Chief Financial Officer, as appropriate to allow
timely decisions regarding required disclosure.
Internal
Control over Financial Reporting
Managements
Annual Report on Internal Control Over Financial Reporting and
Attestation Report of Registered Public Accounting
Firm
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002,
we have included a report of managements assessment of the
design and effectiveness of our internal controls as part of
this annual report on
Form 10-K
for the fiscal year ended December 31, 2009.
Hein & Associates LLP, or Hein, our independent
registered public accounting firm, also attested to, and
reported on, our internal control over financial reporting.
Managements report and Heins attestation report are
referenced on
page F-1
under the captions Managements Report on Internal
Control over Financial Reporting and Report of
Independent Registered Public Accounting Firm
Internal Control over Financial Reporting and are
incorporated herein by reference.
Changes
in Internal Control over Financial Reporting
No changes to our internal control over financial reporting
occurred during the quarter ended December 31, 2009 that
have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting (as
defined in
Rules 13a-15(f)
and
15d-15(f)
under the Exchange Act).
|
|
Item 9A(T).
|
Controls
and Procedures.
|
Not applicable.
|
|
Item 9B.
|
Other
Information.
|
None.
59
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance.
|
Information required under Item 10, Directors,
Executive Officers and Corporate Governance will be
contained under the captions Election of
Directors Directors and Executive
Officers to be provided in our proxy statement for our
2010 annual meeting of stockholders to be filed with the SEC on
or before April 30, 2010, which are incorporated herein by
reference. Additional information regarding our corporate
governance guidelines as well as the complete texts of our Code
of Conduct and the charters of our Audit Committee and our
Nominating and Compensation Committee may be found on our
website at www.approachresources.com.
|
|
Item 11.
|
Executive
Compensation.
|
Information required by Item 11 of this report will be
contained under the caption Executive Compensation
in our proxy statement for our 2010 annual meeting of
stockholders to be filed with the SEC on or before
April 30, 2010, which is incorporated herein by reference.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
|
Information required by Item 12 of this report will be
contained under the caption Stock Ownership Matters
in our proxy statement for our 2010 annual meeting of
stockholders to be filed with the SEC on or before
April 30, 2010, which is incorporated herein by reference.
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence.
|
Information required by Item 13 of this report will be
contained under the captions Certain Relationships and
Related Party Transactions and Corporate
Governance in our definitive proxy statement for our 2010
annual meeting of stockholders to be filed with the SEC on or
before April 30, 2010, which are incorporated herein by
reference.
|
|
Item 14.
|
Principal
Accounting Fees and Services.
|
Information required by Item 14 of this report will be
contained under the caption Independent Registered Public
Accountants in our definitive proxy statement for our 2010
annual meeting of stockholders to be filed with the SEC on or
before April 30, 2010, which is incorporated herein by
reference.
PART IV
|
|
Item 15.
|
Exhibits,
Financial Statement Schedules.
|
|
|
(a)
|
Documents
Filed as Part of this Report
|
|
|
(1)
|
and
(2) Financial Statements and Financial Statement
Schedules.
|
See Index to Consolidated Financial Statements on
page F-1.
See Index to Exhibits on page 66 for a
description of the exhibits filed as part of this report.
60
GLOSSARY
OF SELECTED OIL AND GAS TERMS
The following is a description of the meanings of some of the
oil and gas industry terms used in this report.
3-D
seismic. (Three Dimensional Seismic Data)
Geophysical data that depicts the subsurface strata in three
dimensions.
3-D seismic
data typically provides a more detailed and accurate
interpretation of the subsurface strata than two dimensional
seismic data.
Basin. A large natural depression on the
earths surface in which sediments generally brought by
water accumulate.
Bbl. One stock tank barrel, of 42
U.S. gallons liquid volume, used herein in reference to
oil, condensate or natural gas liquids.
Bcfe. Billion cubic feet of natural gas
equivalent, determined using the ratio of six Mcf of gas to one
Bbl of oil, condensate or gas liquids.
Btu or British Thermal Unit. The quantity of
heat required to raise the temperature of one pound of water by
one degree Fahrenheit.
Completion. The installation of permanent
equipment for production of oil or gas, or, in the case of a dry
well, to reporting to the appropriate authority that the well
has been abandoned.
Developed acreage. The number of acres that
are allocated or assignable to productive wells or wells that
are capable of production.
Developed oil and gas reserves. Has the
meaning given to such term in
Rule 4-10(a)(6)
of
Regulation S-X,
which defines proved 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.
Developmental well. A well drilled within the
proved boundaries of an oil or gas reservoir with the intention
of completing the stratigraphic horizon known to be productive.
Dry hole. An exploratory, development or
extension well that proved to be incapable of producing either
oil or gas in sufficient quantities to justify completion as an
oil or gas well.
Dry hole costs. Costs incurred in drilling a
well, assuming a well is not successful, including plugging and
abandonment costs.
Exploitation. Ordinarily considered to be a
form of development within a known reservoir.
Exploratory well. A well drilled to find and
produce oil or gas reserves not classified as proved, to find a
new reservoir in a field previously found to be productive of
oil or gas in another reservoir or to extend a known reservoir.
Field. An area consisting of either a single
reservoir or multiple reservoirs, all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition.
Fracing or Fracture stimulation
technology. The technique of improving a
wells production or injection rates by pumping a mixture
of fluids into the formation and rupturing the rock, creating an
artificial channel. As part of this technique, sand or other
material may also be injected into the formation to keep the
channel open, so that fluids or gases may more easily flow
through the formation.
Gross acres or gross wells. The total acres or
wells, as the case may be, in which a working interest is owned.
61
Lease operating expenses. The expenses of
lifting oil or gas from a producing formation to the surface,
and the transportation and marketing thereof, constituting part
of the current operating expenses of a working interest, and
also including labor, superintendence, supplies, repairs, short
lived assets, maintenance, allocated overhead costs, ad valorem
taxes and other expenses incidental to production, but excluding
lease acquisition or drilling or completion expenses.
LNG. Liquefied natural gas.
MBbls. Thousand barrels of oil or other liquid
hydrocarbons.
Mcf. Thousand cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent,
determined using the ratio of six Mcf of gas to one Bbl of oil,
condensate or gas liquids.
MMBtu. Million British thermal units.
MMcf. Million cubic feet of gas.
MMcfe. Million cubic feet equivalent,
determined using the ratio of six Mcf of gas to one Bbl of oil,
condensate or gas liquids.
Net acres or net wells. The sum of the
fractional working interests owned in gross acres or wells, as
the case may be.
NGLs. Natural gas liquids.
NYMEX. New York Mercantile Exchange.
Productive well. A, exploratory, development
or extension well that is not a dry well.
Prospect. A specific geographic area which,
based on supporting geological, geophysical or other data and
also preliminary economic analysis using reasonably anticipated
prices and costs, is deemed to have potential for the discovery
of commercial hydrocarbons.
Proved developed producing reserves. Proved
developed oil and gas reserves that are expected to be recovered
from completion intervals currently open in existing wells and
capable of production to market.
Proved oil and gas reserves. Has the meaning
given to such term in
Rule 4-10(a)(22)
of
Regulation S-X,
which defines proved reserves as follows:
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.
62
(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.
PV-10 or
present value of estimated future net
revenues. An estimate of the present value of the
future net revenues from proved oil and gas reserves after
deducting estimated production and ad valorem taxes, future
capital costs and operating expenses, but before deducting any
estimates of federal income taxes. The estimated future net
revenues are discounted at an annual rate of 10%, in accordance
with the SECs practice, to determine their present
value. The present value is shown to indicate the effect
of time on the value of the revenue stream and should not be
construed as being the fair market value of the properties.
Estimates of
PV-10 are
made using oil and gas prices and operating costs at the date
indicated and held constant for the life of the reserves.
Reserve life index. This index is calculated
by dividing year-end 2009 reserves by 2009 production of
8,808 MMcfe to estimate the number of years of remaining
production.
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.
Spacing. The distance between wells producing
from the same reservoir. Spacing is expressed in terms of acres,
e.g.,
40-acre
spacing, and is established by regulatory agencies.
Standardized measure. The present value of
estimated future net revenues to be generated from the
production of proved reserves, determined in accordance with the
rules and regulations of the SEC (using prices and costs in
effect as of the period end date) without giving effect to
non-property related expenses such as general and administrative
expenses, debt service and future income tax expenses or to
depletion, depreciation and amortization and discounted using an
annual discount rate of 10%. Standardized measure does not give
effect to derivative transactions.
Successful well. A well that is found to be
capable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of such production exceed production
expenses and taxes.
Tight gas sands. A formation with low
permeability that produces natural gas with low flow rates for
long periods of time.
Unconventional resources or reserves. Natural
gas or oil resources or reserves from (i) low-permeability
sandstone and shale formations, such as tight gas and gas
shales, respectively, and (ii) coalbed methane.
63
Undeveloped acreage. Lease acreage on which
wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil or gas
regardless of whether or not such acreage contains proved
reserves.
Undeveloped oil and gas reserves. Has the
meaning given to such term in
Rule 4-10(a)(31)
of
Regulation S-X,
which defines proved undeveloped reserves as follows:
Proved undeveloped oil and gas reserves are reserves that are
expected to be recovered from new 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 or by other evidence using reliable
technology establishing reasonable certainty.
Working interest. The operating interest that
gives the owner the right to drill, produce and conduct
operating activities on the property and receive a share of
production.
Workover. Operations on a producing well to
restore or increase production.
/d. Per day when used with
volumetric units or dollars.
64
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
APPROACH RESOURCES INC.
J. Ross Craft
President and Chief Executive Officer
Date: March 12, 2010
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities indicated and
on March 12, 2010.
|
|
|
|
|
Signature
|
|
Title
|
|
|
|
|
/s/ J.
Ross Craft
J.
Ross Craft
|
|
President, Chief Executive Officer and Director
(Principal Executive Officer)
|
|
|
|
/s/ Steven
P. Smart
Steven
P. Smart
|
|
Executive Vice President and Chief Financial Officer
(Principal Financial and Principal Accounting Officer)
|
|
|
|
/s/ Bryan
H. Lawrence
Bryan
H. Lawrence
|
|
Director and Chairman of the Board of Directors
|
|
|
|
/s/ James
H. Brandi
James
H. Brandi
|
|
Director
|
|
|
|
/s/ James
C. Crain
James
C. Crain
|
|
Director
|
|
|
|
/s/ Sheldon
B. Lubar
Sheldon
B. Lubar
|
|
Director
|
|
|
|
/s/ Christopher
J. Whyte
Christopher
J. Whyte
|
|
Director
|
65
MANAGEMENTS
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining
adequate internal control over financial reporting (as defined
in
Rule 13a-15(f)
under the Securities Exchange Act of 1934). Our internal control
over financial reporting is designed to provide reasonable
assurance to management and our board of directors regarding the
preparation and fair presentation of published financial
statements. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect
misstatements. Therefore, even those systems determined to be
effective can provide only reasonable assurance with respect to
financial statement preparation and presentation. Management
assessed the effectiveness of our internal control over
financial reporting as of December 31, 2009. In making this
assessment, management used the criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO) in Internal Control Integrated Framework.
Based on our assessment, we believe that, as of
December 31, 2009, our internal control over financial
reporting is effective based on those criteria.
|
|
|
|
|
|
|
|
|
|
|
By:
|
|
/s/ J. Ross Craft
|
|
|
|
By:
|
|
/s/ Steven P. Smart
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
J. Ross Craft
|
|
|
|
|
|
Steven P. Smart
|
|
|
|
|
President and Chief Executive Officer
|
|
|
|
|
|
Executive Vice President and Chief Financial Officer
|
|
|
Fort Worth, Texas
March 12, 2010
F-2
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Approach Resources Inc.
We have audited Approach Resources Inc. and subsidiaries
(collectively, the Company) internal control over
financial reporting as of December 31, 2009, based on
criteria established in Internal Control Integrated
Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission. The Companys 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 Managements Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion
on the Companys internal control over financial reporting
based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk. Our audit also included performing such other
procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our
opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (a) pertain to the
maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the
assets of the company; (b) 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 (c) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use,
or disposition of the companys assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as
of December 31, 2009, based on criteria established in
Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Approach Resources Inc. and
subsidiaries as of December 31, 2009 and 2008, and the
related statements of operations, changes in stockholders
equity, cash flows and comprehensive (loss) income for each of
the three years in the period ended December 31, 2009 and
our report dated March 12, 2010, expressed an unqualified
opinion.
/s/ HEIN &
ASSOCIATES LLP
Dallas, Texas
March 12, 2010
F-3
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Approach Resources Inc.
We have audited the accompanying consolidated balance sheets of
Approach Resources Inc. and subsidiaries (collectively, the
Company) as of December 31, 2009 and 2008, and
the related consolidated statements of operations, changes in
stockholders equity, cash flows and comprehensive (loss)
income for each of the three years in the period ended
December 31, 2009. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. 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 Approach Resources Inc. and subsidiaries as of
December 31, 2009 and 2008, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2009, in conformity with
U.S. generally accepted accounting principles.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
Companys internal control over financial reporting as of
December 31, 2009, based on criteria established in
Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated March 12, 2010 expressed
an unqualified opinion on the effectiveness of the
Companys internal control over financial reporting.
/s/ HEIN &
ASSOCIATES LLP
Dallas, Texas
March 12, 2010
F-4
Approach
Resources Inc. and Subsidiaries
Consolidated
Balance Sheets
(In thousands, except shares and per-share amounts)
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
ASSETS
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2,685
|
|
|
$
|
4,077
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Joint interest owners
|
|
|
3,088
|
|
|
|
16,228
|
|
Oil and gas sales
|
|
|
4,607
|
|
|
|
5,936
|
|
Unrealized gain on commodity derivatives
|
|
|
786
|
|
|
|
8,017
|
|
Prepaid expenses and other current assets
|
|
|
837
|
|
|
|
579
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
12,003
|
|
|
|
34,837
|
|
PROPERTIES AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
Oil and gas properties, at cost, using the successful efforts
method of accounting
|
|
|
387,792
|
|
|
|
362,805
|
|
Furniture, fixtures and equipment
|
|
|
1,540
|
|
|
|
977
|
|
|
|
|
|
|
|
|
|
|
|
|
|
389,332
|
|
|
|
363,782
|
|
Less accumulated depletion, depreciation and amortization
|
|
|
(84,849
|
)
|
|
|
(60,378
|
)
|
|
|
|
|
|
|
|
|
|
Net properties and equipment
|
|
|
304,483
|
|
|
|
303,404
|
|
OTHER ASSETS
|
|
|
2,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
318,926
|
|
|
$
|
338,241
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Advances from non-operators
|
|
$
|
2,689
|
|
|
$
|
|
|
Accounts payable
|
|
|
3,074
|
|
|
|
13,564
|
|
Oil and gas sales payable
|
|
|
3,774
|
|
|
|
4,631
|
|
Accrued liabilities
|
|
|
10,935
|
|
|
|
9,810
|
|
Current portion of deferred income taxes
|
|
|
|
|
|
|
2,770
|
|
Unrealized loss on commodity derivatives
|
|
|
1,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
21,996
|
|
|
|
30,775
|
|
NON-CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
32,319
|
|
|
|
43,537
|
|
Unrealized loss on commodity derivatives
|
|
|
1,144
|
|
|
|
|
|
Deferred income taxes
|
|
|
38,374
|
|
|
|
35,891
|
|
Asset retirement obligations
|
|
|
4,597
|
|
|
|
4,225
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
98,430
|
|
|
|
114,428
|
|
COMMITMENTS AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY :
|
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par value, 10,000,000 shares
authorized none outstanding
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value, 90,000,000 shares
authorized, 20,959,285 and 20,715,357 issued and outstanding,
respectively
|
|
|
209
|
|
|
|
207
|
|
Additional paid-in capital
|
|
|
168,993
|
|
|
|
167,349
|
|
Retained earnings
|
|
|
51,524
|
|
|
|
56,753
|
|
Accumulated other comprehensive loss
|
|
|
(230
|
)
|
|
|
(496
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
220,496
|
|
|
|
223,813
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
318,926
|
|
|
$
|
338,241
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to these consolidated financial
statements.
F-5
Approach
Resources Inc. and Subsidiaries
Consolidated
Statements of Operations
(In thousands, except shares and per-share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
40,648
|
|
|
$
|
79,869
|
|
|
$
|
39,114
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
7,777
|
|
|
|
7,621
|
|
|
|
3,815
|
|
Severance and production taxes
|
|
|
1,996
|
|
|
|
4,202
|
|
|
|
1,659
|
|
Exploration
|
|
|
1,621
|
|
|
|
1,478
|
|
|
|
883
|
|
Impairment of unproved properties
|
|
|
2,964
|
|
|
|
6,379
|
|
|
|
267
|
|
General and administrative
|
|
|
10,617
|
|
|
|
8,881
|
|
|
|
12,667
|
|
Depletion, depreciation and amortization
|
|
|
24,660
|
|
|
|
23,710
|
|
|
|
13,098
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
49,635
|
|
|
|
52,271
|
|
|
|
32,389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING (LOSS) INCOME
|
|
|
(8,987
|
)
|
|
|
27,598
|
|
|
|
6,725
|
|
OTHER:
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of investment
|
|
|
|
|
|
|
(917
|
)
|
|
|
|
|
Interest expense, net
|
|
|
(1,787
|
)
|
|
|
(1,269
|
)
|
|
|
(5,219
|
)
|
Realized gain on commodity derivatives
|
|
|
14,659
|
|
|
|
2,936
|
|
|
|
4,732
|
|
Unrealized (loss) gain on commodity derivatives
|
|
|
(9,899
|
)
|
|
|
7,149
|
|
|
|
(3,637
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(LOSS) INCOME BEFORE INCOME TAX (BENEFIT) PROVISION
|
|
|
(6,014
|
)
|
|
|
35,497
|
|
|
|
2,601
|
|
INCOME TAX (BENEFIT) PROVISION
|
|
|
(785
|
)
|
|
|
12,111
|
|
|
|
(108
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET (LOSS) INCOME
|
|
$
|
(5,229
|
)
|
|
$
|
23,386
|
|
|
$
|
2,709
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(LOSS) EARNINGS PER SHARE:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.25
|
)
|
|
$
|
1.13
|
|
|
$
|
0.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
(0.25
|
)
|
|
$
|
1.12
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
20,869,832
|
|
|
|
20,647,339
|
|
|
|
11,036,799
|
|
Diluted
|
|
|
20,869,832
|
|
|
|
20,824,905
|
|
|
|
11,183,707
|
|
See accompanying notes to these consolidated financial
statements.
F-6
Approach
Resources Inc. and Subsidiaries
Consolidated
Statements of Changes in Stockholders Equity
for the
Years Ended December 31, 2007, 2008 and 2009
(In thousands, except shares and per-share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loans to
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
|
|
|
Stockholders,
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
Earnings
|
|
|
Including
|
|
|
Other
|
|
|
|
|
|
|
Common Stock
|
|
|
Paid-in
|
|
|
(Accumulated
|
|
|
Accrued
|
|
|
Comprehensive
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Deficit)
|
|
|
Interest
|
|
|
Income (Loss)
|
|
|
Total
|
|
|
BALANCES, January 1, 2007
|
|
|
9,735,312
|
|
|
|
97
|
|
|
|
43,001
|
|
|
|
30,658
|
|
|
|
(4,184
|
)
|
|
|
|
|
|
|
69,572
|
|
Retirement of loans to stockholders
|
|
|
(253,650
|
)
|
|
|
(2
|
)
|
|
|
(4,182
|
)
|
|
|
|
|
|
|
4,184
|
|
|
|
|
|
|
|
|
|
Issuance of common shares to management and directors for
compensation
|
|
|
411,041
|
|
|
|
4
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of stock upon exercise of stock options
|
|
|
72,114
|
|
|
|
1
|
|
|
|
239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
240
|
|
Share-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
4,646
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,646
|
|
Issuance of common stock upon conversion of convertible notes
|
|
|
1,841,262
|
|
|
|
18
|
|
|
|
20,530
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,548
|
|
Beneficial conversion feature of convertible notes
|
|
|
|
|
|
|
|
|
|
|
1,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,547
|
|
Issuance of shares in initial public offering
|
|
|
6,598,572
|
|
|
|
66
|
|
|
|
73,574
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73,640
|
|
Offering costs related to the initial public offering
|
|
|
|
|
|
|
|
|
|
|
(1,503
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,503
|
)
|
Issuance of shares for acquisition of oil and gas properties
|
|
|
4,239,243
|
|
|
|
42
|
|
|
|
50,829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,871
|
|
Purchase and cancellation of common stock
|
|
|
(2,021,148
|
)
|
|
|
(20
|
)
|
|
|
(22,536
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22,556
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,709
|
|
|
|
|
|
|
|
|
|
|
|
2,709
|
|
Foreign currency translation adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
105
|
|
|
|
105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2007
|
|
|
20,622,746
|
|
|
|
206
|
|
|
|
166,141
|
|
|
|
33,367
|
|
|
|
|
|
|
|
105
|
|
|
|
199,819
|
|
Issuance of stock upon exercise of stock options
|
|
|
63,459
|
|
|
|
1
|
|
|
|
212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
213
|
|
Restricted stock issuance
|
|
|
29,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
1,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,100
|
|
Surrender of restricted shares for payment of income taxes
|
|
|
|
|
|
|
|
|
|
|
(54
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(54
|
)
|
Adjustment to additional paid-in capital for tax shortfall upon
vesting of restricted shares
|
|
|
|
|
|
|
|
|
|
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(50
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23,386
|
|
|
|
|
|
|
|
|
|
|
|
23,386
|
|
Foreign currency translation adjustments, net of related income
tax of $256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(601
|
)
|
|
|
(601
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2008
|
|
|
20,715,357
|
|
|
$
|
207
|
|
|
$
|
167,349
|
|
|
$
|
56,753
|
|
|
$
|
|
|
|
$
|
(496
|
)
|
|
|
223,813
|
|
Issuance of common shares to directors for compensation
|
|
|
50,845
|
|
|
|
|
|
|
|
378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
378
|
|
Restricted stock issuance, net of cancellations
|
|
|
202,040
|
|
|
|
2
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
1,448
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,448
|
|
Surrender of restricted shares for payment of income taxes
|
|
|
(8,957
|
)
|
|
|
|
|
|
|
(68
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(68
|
)
|
Adjustment to additional paid-in capital for tax shortfall upon
vesting of restricted shares
|
|
|
|
|
|
|
|
|
|
|
(112
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(112
|
)
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,229
|
)
|
|
|
|
|
|
|
|
|
|
|
(5,229
|
)
|
Foreign currency translation adjustments, net of related income
tax of $118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
266
|
|
|
|
266
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2009
|
|
|
20,959,285
|
|
|
$
|
209
|
|
|
$
|
168,993
|
|
|
$
|
51,524
|
|
|
|
|
|
|
$
|
(230
|
)
|
|
$
|
220,496
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to these consolidated financial
statements.
F-7
Approach
Resources Inc. and Subsidiaries
Consolidated
Statements of Cash Flows
(In thousands, except shares and per-share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(5,229
|
)
|
|
$
|
23,386
|
|
|
$
|
2,709
|
|
Adjustments to reconcile net (loss) income to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
24,660
|
|
|
|
23,710
|
|
|
|
13,098
|
|
Non-cash interest expense on convertible notes
|
|
|
|
|
|
|
|
|
|
|
2,095
|
|
Unrealized loss (gain) on commodity derivatives
|
|
|
9,899
|
|
|
|
(7,149
|
)
|
|
|
3,637
|
|
Impairment of unproved properties
|
|
|
2,964
|
|
|
|
6,379
|
|
|
|
267
|
|
Impairment of investment
|
|
|
|
|
|
|
917
|
|
|
|
|
|
Exploration expense
|
|
|
1,621
|
|
|
|
1,478
|
|
|
|
883
|
|
Share-based compensation expense
|
|
|
1,826
|
|
|
|
1,100
|
|
|
|
4,646
|
|
Deferred income taxes
|
|
|
(785
|
)
|
|
|
12,148
|
|
|
|
(296
|
)
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
12,352
|
|
|
|
(11,501
|
)
|
|
|
(2,657
|
)
|
Prepaid expenses and other current assets
|
|
|
71
|
|
|
|
(38
|
)
|
|
|
(232
|
)
|
Accounts payable
|
|
|
(7,863
|
)
|
|
|
8,105
|
|
|
|
(787
|
)
|
Oil and gas sales payable
|
|
|
(857
|
)
|
|
|
2,837
|
|
|
|
(3,146
|
)
|
Accrued liabilities
|
|
|
1,102
|
|
|
|
(4,937
|
)
|
|
|
10,529
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
39,761
|
|
|
|
56,435
|
|
|
|
30,746
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas properties
|
|
|
(28,990
|
)
|
|
|
(100,089
|
)
|
|
|
(51,845
|
)
|
Additions to furniture, fixtures and equipment, net
|
|
|
(563
|
)
|
|
|
(544
|
)
|
|
|
(178
|
)
|
Investments
|
|
|
|
|
|
|
|
|
|
|
(917
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities
|
|
|
(29,553
|
)
|
|
|
(100,633
|
)
|
|
|
(52,940
|
)
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Loan origination fees
|
|
|
(400
|
)
|
|
|
|
|
|
|
(140
|
)
|
Borrowings under credit facility
|
|
|
67,407
|
|
|
|
121,687
|
|
|
|
64,285
|
|
Repayment of amounts outstanding under credit facility
|
|
|
(78,625
|
)
|
|
|
(78,150
|
)
|
|
|
(111,904
|
)
|
Proceeds from convertible notes
|
|
|
|
|
|
|
|
|
|
|
20,000
|
|
Proceeds from issuance of common stock
|
|
|
|
|
|
|
213
|
|
|
|
72,377
|
|
Surrender of restricted shares for payment of income taxes
|
|
|
|
|
|
|
(54
|
)
|
|
|
|
|
Purchase of common stock
|
|
|
|
|
|
|
|
|
|
|
(22,556
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash (used in) provided by financing activities
|
|
|
(11,618
|
)
|
|
|
43,696
|
|
|
|
22,062
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHANGE IN CASH AND CASH EQUIVALENTS
|
|
|
(1,410
|
)
|
|
|
(502
|
)
|
|
|
(132
|
)
|
EFFECT OF FOREIGN CURRENCY TRANSLATION ON CASH AND CASH
EQUIVALENTS
|
|
|
18
|
|
|
|
(206
|
)
|
|
|
6
|
|
CASH AND CASH EQUIVALENTS, beginning of year
|
|
|
4,077
|
|
|
|
4,785
|
|
|
|
4,911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, end of year
|
|
$
|
2,685
|
|
|
$
|
4,077
|
|
|
$
|
4,785
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
1,790
|
|
|
$
|
894
|
|
|
$
|
4,117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for income taxes
|
|
$
|
|
|
|
$
|
397
|
|
|
$
|
1,287
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTION:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of oil and gas properties
|
|
$
|
|
|
|
$
|
509
|
|
|
$
|
60,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations capitalized
|
|
$
|
170
|
|
|
$
|
3,504
|
|
|
$
|
257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conversion of convertible notes and accrued interest into common
stock
|
|
$
|
|
|
|
$
|
|
|
|
$
|
20,548
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement of loans to stockholders in exchange for shares of
common stock
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to these consolidated financial
statements.
F-8
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
|
|
1.
|
Summary
of Significant Accounting Policies
|
Organization
and Nature of Operations
Approach Resources Inc. (Approach, ARI,
the Company, we, us or
our) is an independent energy company engaged in the
exploration, development, production and acquisition of
unconventional natural gas and oil properties in the United
States. We focus on finding and developing natural gas and oil
reserves in tight sands and shale gas. We currently operate or
have oil and gas properties or interests in Texas, Kentucky and
New Mexico.
Consolidation,
Basis of Presentation and Significant Estimates
The accompanying consolidated financial statements have been
prepared in accordance with accounting principles generally
accepted in the United States of America and include the
accounts of the Company and its wholly-owned subsidiaries.
Intercompany accounts and transactions are eliminated. In
preparing the accompanying financial statements, management has
made certain estimates and assumptions that affect reported
amounts in the financial statements and disclosures of
contingencies. Actual results may differ from those estimates.
Significant assumptions are required in the valuation of proved
oil and natural gas reserves, the capital expenditure accrual,
share-based compensation, and asset retirement obligations. It
is at least reasonably possible these estimates could be revised
in the near term, and these revisions could be material.
On November 7, 2007, our board of directors approved a
three-for-one
stock split in the form of a stock dividend on the issued and
outstanding shares of the Companys common stock, which
became effective at the completion of our initial public
offering (IPO) on November 14, 2007. Also on
November 14, 2007, we acquired all of the outstanding
capital stock of Approach Oil & Gas Inc.
(AOG). The stockholders of AOG received
989,157 shares of Company common stock in exchange for all
of AOGs common shares outstanding at that date.
All common shares and per share amounts in the accompanying
consolidated financial statements and notes to consolidated
financial statements have been adjusted for all periods to give
effect to the stock split and the acquisition of AOG. Certain
prior year amounts have been reclassified to conform to current
year presentation. These classifications have no impact on the
net income or loss reported.
Cash and
Cash Equivalents
We consider all highly liquid debt instruments purchased with an
original maturity of three months or less to be cash
equivalents. At times, the amount of cash and cash equivalents
on deposit in financial institutions exceeds federally insured
limits. We monitor the soundness of the financial institutions
and believe the Companys risk is negligible.
Financial
Instruments
The carrying amounts of financial instruments including cash and
cash equivalents, accounts receivable, notes receivable,
accounts payable and accrued liabilities and long-term debt
approximate fair value, as of December 31, 2009 and 2008.
See Note 7 for commodity derivative fair value disclosures.
F-10
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Oil and
Gas Properties and Operations
Capitalized
Costs
Our oil and gas properties comprised the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Mineral interests in properties:
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
10,990
|
|
|
$
|
12,687
|
|
Proved properties
|
|
|
12,319
|
|
|
|
11,849
|
|
Wells and related equipment and facilities
|
|
|
361,573
|
|
|
|
332,289
|
|
Uncompleted wells, equipment and facilities
|
|
|
2,910
|
|
|
|
5,980
|
|
|
|
|
|
|
|
|
|
|
Total costs
|
|
|
387,792
|
|
|
|
362,805
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(84,135
|
)
|
|
|
(59,960
|
)
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
303,657
|
|
|
$
|
302,845
|
|
|
|
|
|
|
|
|
|
|
We follow the successful efforts method of accounting for our
oil and gas producing activities. Costs to acquire mineral
interests in oil and gas properties and to drill and equip
development wells and related asset retirement costs are
capitalized. Costs to drill exploratory wells are capitalized
pending determination of whether the wells have proved reserves.
If we determine that the wells do not have proved reserves, the
costs are charged to expense. There were no exploratory wells
capitalized pending determination of whether the wells have
proved reserves at December 31, 2009 or 2008. Geological
and geophysical costs, including seismic studies and costs of
carrying and retaining unproved properties are charged to
expense as incurred. We capitalize interest on expenditures for
significant exploration and development projects that last more
than six months while activities are in progress to bring the
assets to their intended use. Through December 31, 2009, we
have capitalized no interest costs because our exploration and
development projects generally last less than six months. Costs
incurred to maintain wells and related equipment are charged to
expense as incurred.
On the sale or retirement of a complete unit of a proved
property, the cost and related accumulated depreciation,
depletion, and amortization are eliminated from the property
accounts, and the resultant gain or loss is recognized. On the
retirement or sale of a partial unit of proved property, the
cost is charged to accumulated depreciation, depletion, and
amortization with a resulting gain or loss recognized in income.
Capitalized amounts attributable to proved oil and gas
properties are depleted by the
unit-of-production
method over proved reserves using the unit conversion ratio of
six Mcf of gas to one Bbl of oil. Depreciation and depletion
expense for oil and gas producing property and related equipment
was $24.2 million, $23.3 million and $13 million
for the years ended December 31, 2009, 2008 and 2007,
respectively.
Unproved oil and gas properties that are individually
significant are periodically assessed for impairment of value,
and a loss is recognized at the time of impairment by providing
an impairment allowance. We recorded an impairment of $3 and
$6.4 million during the years ended December 31, 2009
and 2008, respectively related to our assessment of unproved
properties. The 2009 impairment resulted from a write-off of
$3 million in acreage costs in Northeast British Columbia,
and represents the remaining carrying value we have recorded for
the project. The impairment recorded during the year ended
December 31, 2008, resulted from write-offs related to
drilling costs in our Boomerang project and drilling and
completion costs in our Northeast British Columbia project.
During the year ended December 31, 2008, we determined that
the future cash flows from drilling costs relating to these
projects will not exceed the capitalized costs due to market
factors. We recorded an impairment during the year ended
December 31, 2007, totaling $267,000, and resulting from
our conclusion that proved reserves would not be economically
recovered from approximately 2,282 acres in Ozona
Northeast, leases for which expired in April 2008.
F-11
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Capitalized costs related to proved oil and gas properties,
including wells and related equipment and facilities, are
evaluated for impairment based on an analysis of undiscounted
future net cash flows in accordance with ASC 360, formerly
Statement of Financial Accounting Standards 144, Accounting
for the Impairment or Disposal of Long-Lived Assets. If
undiscounted cash flows are insufficient to recover the net
capitalized costs related to proved properties, then we
recognize an impairment charge in income from operations equal
to the difference between the net capitalized costs related to
proved properties and their estimated fair values based on the
present value of the related future net cash flows. We noted no
impairment of our proved properties based on our analysis for
the years ended December 31, 2009, 2008 or 2007.
On the sale of an entire interest in an unproved property for
cash or cash equivalent, gain or loss on the sale is recognized,
taking into consideration the amount of any recorded impairment
if the property had been assessed individually. If a partial
interest in an unproved property is sold, the amount received is
treated as a reduction of the cost of the interest retained.
Ozona
Northeast Deep Rights Acquisition
On July 1, 2008, we acquired an additional 95% working
interest in all depths below the top of the Strawn formation,
compression facilities and rights to approximately 75 miles
of gathering lines in our Ozona Northeast field in Crockett and
Schleicher Counties, Texas. The properties were acquired from
J. Cleo Thompson & James Cleo
Thompson, Jr., L.P. and certain other sellers. Before the
acquisition, we owned a 100% working interest above the top of
the Strawn formation and a 5% working interest below the top of
the Strawn formation in Ozona Northeast. As a result of the
acquisition, we now own substantially all working interests in
all depths of the subsurface in Ozona Northeast.
The purchase price was $12 million subject to post-closing
adjustments. We received a post-closing settlement of
$1.1 million subsequent to December 31, 2008. Of the
purchase price, $500,000 is to be paid pending certain
right-of-way
matters to be cured. Our preliminary purchase price allocation
was $9.5 million to oil and gas properties and
$2 million to gathering system, compression facilities and
related equipment. Funding was provided through borrowings under
our revolving credit facility.
The following is a summary of the purchase price and its
allocation (in thousands):
|
|
|
|
|
Purchase price:
|
|
|
|
|
Cash paid
|
|
$
|
11,500
|
|
Asset retirement obligations assumed
|
|
|
995
|
|
Post-closing purchase price adjustments
|
|
|
(1,154
|
)
|
|
|
|
|
|
Total
|
|
$
|
11,341
|
|
|
|
|
|
|
Allocation:
|
|
|
|
|
Wells, equipment and related facilities
|
|
$
|
11,041
|
|
Mineral interests in oil and gas properties
|
|
|
300
|
|
|
|
|
|
|
Total
|
|
$
|
11,341
|
|
|
|
|
|
|
Oil and
Gas Operations
Revenue
and Accounts Receivable
We recognize revenue for our production when the quantities are
delivered to or collected by the respective purchaser. Prices
for such production are defined in sales contracts and are
readily determinable based on certain publicly available
indices. All transportation costs are included in lease
operating expense.
F-12
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Accounts receivable, joint interest owners, consist of
uncollateralized joint interest owner obligations due within
30 days of the invoice date. Accounts receivable, oil and
gas sales, consist of uncollateralized accrued revenues due
under normal trade terms, generally requiring payment within 30
to 60 days of production. No interest is charged on
past-due balances. Payments made on all accounts receivable are
applied to the earliest unpaid items. We review accounts
receivable periodically and reduce the carrying amount by a
valuation allowance that reflects our best estimate of the
amount that may not be collectible. No such allowance was
considered necessary at December 31, 2009 or 2008.
Oil and
Gas Sales Payable
Oil and gas sales payable represents amounts collected from
purchasers for oil and gas sales which are either revenues due
to other revenue interest owners or severance taxes due to the
respective state or local tax authorities. Generally, we are
required to remit amounts due under these liabilities within
30 days of the end of the month in which the related
production occurred.
Advances
from Non-Operators
Advances from non-operators represent amounts collected in
advance for joint operating activities. Such amounts are applied
to joint interest accounts receivable as related costs are
incurred.
Production
Costs
Production costs, including compressor rental and repair,
pumpers salaries, saltwater disposal, ad valorem taxes,
insurance, repairs and maintenance, expensed workovers and other
operating expenses are expensed as incurred and included in
lease operating expense on our consolidated statements of
operations.
Exploration expenses include dry hole costs, delay rentals and
geological and geophysical costs.
Dependence
on Major Customers
For the years ended December 31, 2009, 2008 and 2007, we
sold substantially all of our oil and gas produced to six
purchasers. Additionally, substantially all of our accounts
receivable related to oil and gas sales were due from those six
purchasers at December 31, 2009 and 2008. We believe that
there are potential alternative purchasers and that it may be
necessary to establish relationships with new purchasers.
However, there can be no assurance that we can establish such
relationships and that those relationships will result in
increased purchasers. Although we are exposed to a concentration
of credit risk, we believe that all of our purchasers are credit
worthy.
Dependence
on Suppliers
Our industry is cyclical, and from time to time there is a
shortage of drilling rigs, equipment, supplies and qualified
personnel. During these periods, the costs and delivery times of
rigs, equipment and supplies are substantially greater. If the
unavailability or high cost of drilling rigs, equipment,
supplies or qualified personnel were particularly severe in the
areas where we operate, we could be materially and adversely
affected. We believe that there are potential alternative
providers of drilling services and that it may be necessary to
establish relationships with new contractors. However, there can
be no assurance that we can establish such relationships and
that those relationships will result in increased availability
of drilling rigs.
Other
Property
Furniture, fixtures and equipment are carried at cost.
Depreciation of furniture, fixtures and equipment is provided
using the straight-line method over estimated useful lives
ranging from three to ten years. Gain or loss on retirement or
sale or other disposition of assets is included in income in the
period of disposition.
F-13
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Depreciation expense for other property and equipment was
$296,000, $180,000 and $88,000 for the years ended
December 31, 2009, 2008 and 2007, respectively.
Income
Taxes
Deferred tax assets and liabilities are recognized for the
estimated future tax consequences attributable to the
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Deferred tax assets and liabilities are measured using the tax
rate in effect for the year in which 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 in the year of the enacted tax rate change.
Derivative
Activity
All derivative instruments are recorded on the balance sheet at
fair value. Changes in the instruments fair values are
recognized in the statement of operations immediately unless
specific commodity derivative accounting criteria are met. For
qualifying cash flow commodity derivatives, the gain or loss on
the derivative is deferred in accumulated other comprehensive
(loss) income to the extent the commodity derivative is
effective. The ineffective portion of the commodity derivative
is recognized immediately in the statement of operations. Gains
and losses on commodity derivative instruments included in
cumulative other comprehensive (loss) income are reclassified to
oil and natural gas sales revenue in the period that the related
production is delivered. Derivative contracts that do not
qualify for commodity derivative accounting treatment are
recorded as derivative assets and liabilities at fair value in
the balance sheet, and the associated unrealized gains and
losses are recorded as current income or expense in the
statement of operations.
Historically, we have not designated our derivative instruments
as cash-flow hedges. We record our open derivative instruments
at fair value on our consolidated balance sheets as either
unrealized gains or losses on commodity derivatives. We record
changes in such fair value in earnings on our consolidated
statements of operations under the caption entitled
unrealized (loss) gain on commodity derivatives.
Although we have not designated our derivative instruments as
cash-flow hedges, we use those instruments to reduce our
exposure to fluctuations in commodity prices related to our
natural gas and oil production. Unrealized gains and losses, at
fair value, are included on our consolidated balance sheets as
current or non-current assets or liabilities based on the
anticipated timing of cash settlements under the related
contracts. Changes in the fair value of our commodity derivative
contracts are recorded in earnings as they occur and included in
other income (expense) on our consolidated statements of
operations. Realized gains as losses are also included in other
income (expense) on our consolidated statements of operations.
Accrued
Liabilities
Following is a summary of our accrued liabilities at
December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Capital expenditures accrued
|
|
$
|
9,362
|
|
|
$
|
8,173
|
|
Operating expenses and other
|
|
|
1,517
|
|
|
|
1,587
|
|
Income taxes payable
|
|
|
56
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,935
|
|
|
$
|
9,810
|
|
|
|
|
|
|
|
|
|
|
Asset
Retirement Obligations
Our asset retirement obligations relate to future plugging and
abandonment expenses on oil and gas properties. Based on the
expected timing of payments, the full asset retirement
obligation is classified as non-
F-14
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
current. There were no significant changes to the asset
retirement obligations for the years ended December 31,
2009, 2008 and 2007.
Foreign
Currency Translation
The functional currency of the countries in which we operate is
the U.S. dollar in the United States and the Canadian
Dollar in Canada. Assets and liabilities of our Canadian
subsidiary that are denominated in currencies other than the
Canadian Dollar are translated at current exchange rates. Gains
and losses resulting from such translations, along with gains or
losses realized from transactions denominated in currencies
other than the Canadian Dollar are included in operating results
on our statements of operations. For purposes of consolidation,
we translate the assets and liabilities of our Canadian
Subsidiary into U.S. Dollars at current exchange rates
while revenues and expenses are translated at the average rates
in effect for the period. The related translation gains and
losses are included in accumulated other comprehensive loss
within stockholders equity on our consolidated balance
sheets. During the years ended December 31, 2009 and 2007,
we recognized translation gains, net of related income tax, of
$266,000 and $105,000, respectively. During the year ended
December 31, 2008, we recognized a $601,000 translation
loss, net of the related income tax, respectively.
Share-Based
Compensation
We measure and record compensation expense for all share-based
payment awards to employees and outside directors based on
estimated grant date fair values. We recognize compensation
costs for awards granted over the requisite service period based
on the grant date fair value.
Earnings
Per Common Share
We report basic earnings per common share, which excludes the
effect of potentially dilutive securities, and diluted earnings
per common share, which includes the effect of all potentially
dilutive securities unless their impact is anti-dilutive. The
following are reconciliations of the numerators and denominators
of our basic and diluted earnings per share, (dollars in
thousands, except per-share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
Loss
|
|
|
Shares
|
|
|
Per-Share
|
|
|
|
(Numerator)
|
|
|
(Denominator)
|
|
|
Amount
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(5,229
|
)
|
|
|
20,869,832
|
|
|
$
|
(0.25
|
)
|
Effect of dilutive securities(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation, treasury method
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss plus assumed conversions
|
|
$
|
(5,229
|
)
|
|
|
20,869,832
|
|
|
$
|
(0.25
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
Income
|
|
|
Shares
|
|
|
Per-Share
|
|
|
|
(Numerator)
|
|
|
(Denominator)
|
|
|
Amount
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
23,386
|
|
|
|
20,647,339
|
|
|
$
|
1.13
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation, treasury method
|
|
|
|
|
|
|
177,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income plus assumed conversions
|
|
$
|
23,386
|
|
|
|
20,824,905
|
|
|
$
|
1.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-15
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Income
|
|
|
Shares
|
|
|
Per-Share
|
|
|
|
(Numerator)
|
|
|
(Denominator)
|
|
|
Amount
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
2,709
|
|
|
|
11,036,799
|
|
|
$
|
0.25
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation, treasury method
|
|
|
|
|
|
|
146,908
|
|
|
|
|
|
Convertible notes(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income plus assumed conversions
|
|
$
|
2,709
|
|
|
|
11,183,707
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Approximately 410,000 options to purchase our common stock were
excluded from this calculation because they were anti-dilutive. |
|
(2) |
|
The outstanding principal and interest under our convertible
debt was converted on November 7, 2007 into shares of
common stock (see Note 2 for further discussion).
Approximately 1.8 million shares were excluded from assumed
conversions because they were anti-dilutive for the year ended
December 31, 2007. |
Current
Accounting Pronouncements
Effective January 1, 2009, we adopted ASC
260-10
(formerly Staff Position
No. EITF 03-6-1),
Determining whether Instruments Granted in Share-Based
Payment Transactions are Participating Securities, which
provides that unvested share-based payment awards that contain
non-forfeitable rights to dividend or dividend equivalents
(whether paid or unpaid) are participating securities, and,
therefore need to be included in the earnings allocation in
computing earnings per share under the two-class method. We
adopted the provisions of this standard on January 1, 2009,
with no significant impact on our reported earnings per share.
Effective January 1, 2009, we adopted ASC
815-10
(formerly Statement of Financial Accounting Standards
(SFAS) 161, Disclosures about Derivative
Instruments and Hedging Activities, an amendment of FASB
Statement 133), which amends and expands the disclosure
requirements with the intent to provide users of financial
statements with an enhanced understanding of (i) how and
why an entity uses derivative instruments; (ii) how
derivative instruments and the related hedged items are
accounted for; and (iii) how derivative instruments and
related hedged items affect an entitys financial position,
financial performance and cash flows. See Note 7 to our
consolidated financial statements for additional disclosures.
In May 2009, the Financial Accounting Standards Board (the
FASB) issued ASC
855-10
(formerly SFAS No. 165) Subsequent Events,
which establishes general standards of accounting for and
disclosure of events that occur subsequent to the date of our
consolidated financial statements. We adopted this standard upon
issuance with no impact on our financial position or results of
operations.
In June 2009, the FASB issued ASC
105-10
(formerly SFAS No. 168), Accounting Standards
Codificationtm
and the Hierarchy of Generally Accepted Accounting
Principles. The FASB Accounting Standards
Codificationtm
(the Codification) has become the source of
authoritative accounting principles recognized by the FASB to be
applied by nongovernmental entities in the preparation of
financial statements in accordance with Generally Accepted
Accounting Principles (GAAP). All existing
accounting standard documents are superseded by the Codification
and any accounting literature not included in the Codification
will not be authoritative. Rules and interpretive releases of
the SEC issued under the authority of federal securities laws,
however, will continue to be the source of authoritative
generally accepted accounting principles for SEC registrants.
Effective September 30, 2009, all references made to GAAP
in our consolidated financial statements will include the new
Codification numbering system along with original references.
The
F-16
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Codification does not change or alter existing GAAP and,
therefore, will not have an impact on our financial position,
results of operations or cash flows.
On December 31, 2008, the Securities and Exchange
Commission (the SEC) released a Final Rule,
Modernization of Oil and Gas Reporting, approving
revisions designed to modernize oil and gas reserve reporting
requirements. The new reserve rules are effective for our
financial statements for the year ended December 31, 2009
and our 2009 year-end proved reserve estimates. See
Note 12 to our consolidated financial statements for
additional disclosures. The most significant revisions to the
reporting requirements include:
|
|
|
|
|
Commodity prices. Economic producibility of
reserves is now based on the unweighted, arithmetic average of
the closing price on the first day of the month for the
12-month
period prior to fiscal year end, unless prices are defined by
contractual arrangements;
|
|
|
|
Undeveloped oil and gas reserves. Reserves may
be classified as proved undeveloped for undrilled
areas beyond one offsetting drilling unit from a producing well
if there is reasonable certainty that the quantities will be
recovered;
|
|
|
|
Reliable technology. The rules now permit the
use of new technologies to establish the reasonable certainty of
proved reserves if those technologies have been demonstrated
empirically to lead to reliable conclusions about reserves
volumes;
|
|
|
|
Unproved reserves. Probable and possible
reserves may be disclosed separately on a voluntary basis;
|
|
|
|
Preparation of reserves estimates. Disclosure
is required regarding the internal controls used to assure
objectivity in the reserves estimation process and the
qualifications of the technical person primarily responsible for
preparing reserves estimates; and
|
|
|
|
Third party reports. We are now required to
file the report of any third party used to prepare or audit
reserves our estimates.
|
In addition, in January 2010, FASB issued Account Standards
Update (the Update)
2010-03,
Oil and Gas Reserve Estimation and Disclosures, to
provide consistency with the new reserve rules. The Update
amends existing standards to align the reserves calculation and
disclosure requirements under GAAP with the requirements in the
SECs reserve rules. We adopted the new standards effective
December 31, 2009. The new standards are applied
prospectively as a change in estimate.
The new reserve rules resulted in the use of lower prices for
natural gas, oil and NGLs than would have resulted under the
previous reporting requirements. Under the new reserve rules,
our estimated proved reserves increased by 7,860 MMcfe.
Under the previous reserve rules, our estimated total proved
reserves of natural gas, oil and NGLs would have increased by
20,122 MMcfe. Therefore, the effect of the new reserve
rules was a negative revision of 12,262 MMcfe.
Because we use quarter-end reserves and add back current
production to calculate quarterly depletion, depreciation and
amortization expense, or DD&A, adoption of these new
standards had an impact on DD&A for the fourth quarter of
2009. We estimate the impact of using the unweighted, arithmetic
average on the closing price on the first day of each month for
the 12-month
period prior to December 31, 2009, as required by the new
reserve rules, instead of year-end commodity prices, to be an
increase in DD&A for the fourth quarter of 2009 of
approximately $400,000 ($0.01 per share), net of related income
taxes.
In January 2010, the Financial Accounting Standards Board issued
amendments to Fair Value Measurements and Disclosures under ASC
Topic 820. Effective for our 2010 financial statements, this
guidance provides for disclosures of significant transfers in an
out of Levels 1 and 2. In addition, the guidance clarifies
existing disclosure requirements regarding inputs and valuation
techniques as well as the appropriate level of disaggregation
for fair value measurements and disclosures. Effective for our
2011 financial statements, this guidance provides for
disclosures of activity on a gross basis within Level 3
reconciliation.
F-17
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
2.
|
Contribution
Agreement and Initial Public Offering
|
Contribution
Agreement
On November 14, 2007, the Company acquired all of the
outstanding capital stock of AOG and acquired the 30% working
interest in the Ozona Northeast field (the Neo Canyon
interest) that the Company did not already own from Neo
Canyon Exploration, L.P. (Neo Canyon). Upon the
closing of the contribution agreement, Neo Canyon and each of
the stockholders of AOG received shares of Company common stock
in exchange for their respective contributions. Neo Canyon
received an aggregate of 4,239,243 shares of Company common
stock, of which 2,061,290 shares were offered in the
Companys IPO, 156,805 shares were subject to the
over-allotment option granted to the underwriters and
2,021,148 shares were redeemed by the Company for cash. The
stockholders of AOG received an aggregate of 989,157 shares
of Company common stock. Our acquisition of AOG represents a
reorganization of companies under common control. Accordingly,
all of our consolidated financial statements have been presented
to reflect the financial position, results of operations and
cash flows as if we had owned AOG since its inception.
The acquisition cost of the Neo Canyon interest was
$60.7 million, representing 4,239,243 shares of
Company common stock at $12.00 per share, our IPO price, and the
assumption of related deferred income tax liabilities and asset
retirement obligations at that date along with post-closing
purchase price adjustments resulting from operating results of
the properties acquired between the effective date and the
closing date of the acquisition. The existing tax basis assumed
from the acquisition was finalized during the year ended
December 31, 2008. The adjustment made during the year
ended December 31, 2008 resulted in a $376,000 increase in
deferred tax liabilities, $133,000 in additional post-closing
purchase price adjustments and an increase in oil and gas
properties of $509,000. The following is a summary of the final
purchase price and its allocation (in thousands):
|
|
|
|
|
Purchase price:
|
|
|
|
|
Issuance of 4,239,243 shares of Approach Resources Inc.
common stock valued at $12.00 per share
|
|
$
|
50,871
|
|
Deferred tax liabilities assumed
|
|
|
9,465
|
|
Asset retirement obligations assumed
|
|
|
133
|
|
Post-closing purchase price adjustments
|
|
|
265
|
|
|
|
|
|
|
Total
|
|
$
|
60,734
|
|
|
|
|
|
|
Allocation:
|
|
|
|
|
Wells, equipment and related facilities
|
|
$
|
59,936
|
|
Mineral interests in oil and gas properties
|
|
|
798
|
|
|
|
|
|
|
Total
|
|
$
|
60,734
|
|
|
|
|
|
|
F-18
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Our results of operations include the operating results of the
interest acquired from Neo Canyon beginning November 14,
2007. The following condensed pro forma information gives effect
to the acquisition as if it had occurred on January 1,
2006. The pro forma information has been included in the notes
as required by GAAP and is provided for comparison purposes
only. The pro forma financial information is not necessarily
indicative of the financial results that would have occurred had
the acquisition been effective on the dates indicated and should
not be viewed as indicative of operations in the future.
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
December 31,
|
|
|
2007
|
|
2006
|
|
Operating revenues
|
|
$
|
52,285
|
|
|
$
|
66,230
|
|
Total operating expenses
|
|
$
|
38,651
|
|
|
$
|
33,772
|
|
Earnings applicable to common stock
|
|
$
|
7,224
|
|
|
$
|
27,864
|
|
Net earnings per share basic
|
|
$
|
0.49
|
|
|
$
|
2.05
|
|
Net earnings per share diluted
|
|
$
|
0.49
|
|
|
$
|
2.01
|
|
Initial
Public Offering
On November 14, 2007, we completed the IPO of our common
stock. In connection with our IPO and exercise by the
underwriters of their overallotment option, we sold
6,598,572 shares of our common stock in November 2007 at
$12.00 per share. The gross proceeds of our IPO and
over-allotment option were approximately $79.2 million,
which resulted in net proceeds to the Company of
$73.6 million after deducting underwriter discounts and
commissions of approximately $5.6 million. The aggregate
net proceeds of approximately $73.6 million received by the
Company were used as follows (in millions):
|
|
|
|
|
Repayment of revolving credit facility
|
|
$
|
51.1
|
|
Repurchase of stock held by selling stockholder
|
|
$
|
22.5
|
|
Stock
Split
A
three-for-one
stock split in the form of a stock dividend on the issued and
outstanding shares of Company common stock was declared on
November 7, 2007, and was paid on November 14, 2007 in
authorized but unissued shares of Company common stock to
holders of record of shares of common stock at the close of
business on November 13, 2007, so that each share of common
stock outstanding on that date entitled its holder to receive
two additional shares of common stock.
Convertible
Notes
Upon the consummation of the IPO, the convertible notes
discussed in Note 8 and related accrued interest were
automatically converted into shares of our common stock. The
number of shares of common stock issued upon the automatic
conversion of these notes was 920,631 to Yorktown Energy
Partners VII, L.P. and 920,631 to Lubar Equity Fund, LLC. The
shares of common stock that were issued to Yorktown Energy
Partners VII, L.P. and Lubar Equity Fund, LLC upon such
automatic conversion are entitled to the same registration
rights as those provided to certain holders of common stock in
connection with the contribution agreement.
Additionally, we recorded $1.5 million of interest expense
related to a beneficial conversion feature attributable to the
convertible notes at the time of conversion.
F-19
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
3.
|
Loans to
Stockholders and Stockholder Notes Payable
|
During each of the years ended December 31, 2003 and 2004,
we issued 450,000 shares of common stock in exchange for
$585,000 in cash and $3.9 million in full-recourse notes
receivable from employees and entities owned by or affiliated
with management.
During February 2006, one of our employees voluntarily resigned.
At the time of his resignation, the employee held
103,845 shares of ARI common stock and options to acquire
28,845 shares of ARI common stock at $3.33 per share.
Additionally, the employee owed us $334,000 of principal and
interest under a full-recourse note receivable for the initial
purchase of his shares. On February 17, 2006, we entered
into an agreement to repurchase the shares and options, net of
the principal and interest due under the note receivable. We
paid $12.82 per share, the fair value of our common stock on
February 17, 2006, for the 103,845 shares, or
$1.3 million less the outstanding principal and interest of
$334,000 for total cash of $1 million. As discussed in
Note 6, we paid $273,000 in cash to cancel the vested
options held by the employee on February 17, 2006.
On January 8, 2007, the remaining notes and accrued
interest were repaid in exchange for 253,650 shares of
common stock held by management, based on the fair value of ARI
common shares of $16.50 per share at that date. The notes
provided for interest at six percent per annum and were payable
upon the earlier of December 31, 2008, the registration of
the underlying common stock, or upon a merger with another
entity or upon a divestiture of our assets. The notes were
collateralized by the underlying common stock purchased and are
reported in the accompanying balance sheet as loans to
stockholders including accrued interest, reducing
stockholders equity. Interest earned is reported net of
related income tax as a component of additional paid-in capital
in the accompanying statement of changes in stockholders
equity.
The following is a summary of the balance of principal and
interest outstanding under the notes receivable at
December 31, 2006 (in thousands):
|
|
|
|
|
|
|
2006
|
|
|
Principal
|
|
$
|
3,614
|
|
Accrued interest
|
|
|
570
|
|
|
|
|
|
|
Total
|
|
$
|
4,184
|
|
|
|
|
|
|
|
|
4.
|
Revolving
Credit Facility
|
We have a $200 million revolving credit facility with a
borrowing base set at $115 million. The borrowing base is
redetermined semi-annually on or before each April 1 and October
1 based on our oil and gas reserves. We or the lenders can each
request one additional borrowing base redetermination each
calendar year.
Currently, the maturity date under our revolving credit facility
is July 31, 2011. Borrowings bear interest based on the
agent banks prime rate plus an applicable margin ranging
from 1.25% to 2.25%, or the sum of the Eurodollar rate plus an
applicable margin ranging from 2.25% to 3.25%. Margins vary
based on the borrowings outstanding compared to the borrowing
base. In addition, we pay an annual commitment of 0.50% of
non-used borrowings available under our revolving credit
facility.
Effective April 8, 2009, we entered into a fourth amendment
(the Fourth Amendment) to our credit agreement. The
Fourth Amendment reaffirmed the borrowing base of
$100 million under the credit agreement as well as the
commitment percentages of the agent bank and participating
banks. The Fourth Amendment also revised the applicable rate
schedule to (i) increase the Eurodollar rate margin from a
range of 1.25% to 2.00% to a range of 2.25% to 3.25%, determined
by the then-current percentage of the borrowing base that is
drawn, (ii) increase the base rate margin from a flat rate
of 0.00% to a range of 1.25% to 2.25%, determined
F-20
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
by the then-current percentage of the borrowing base that is
drawn, and (iii) increase the unused commitment fee rate
from 0.375% to 0.50%.
Effective July 8, 2009, we entered into a fifth amendment
to our credit agreement, which extended the maturity date under
our revolving credit facility by one year to July 31, 2011.
In consideration for extending the maturity date, we paid a
$250,000 extension fee, calculated as 0.25% of the current
commitment amount of $100 million. The $250,000 fee is
being amortized into interest expense through the extended
maturity date.
Effective October 30, 2009, we entered into a sixth
amendment to our credit agreement, which increased the borrowing
base under the credit agreement to $115 million from
$100 million.
Effective February 1, 2010, we entered into a seventh
amendment to our credit agreement, which replaced The Frost
National Bank as the administrative agent under the Credit
Agreement with JPMorgan Chase Bank, N.A., as successor agent.
We had outstanding borrowings of $32.3 million and
$43.5 million under our revolving credit facility at
December 31, 2009 and 2008, respectively. The weighted
average interest rate applicable to our outstanding borrowings
was 3.20% and 3.25% at December 31, 2009 and 2008,
respectively. We also had outstanding unused letters of credit
under our revolving credit facility totaling $400,000 at
December 31, 2009, which reduce amounts available for
borrowing under our revolving credit facility.
Loans under our revolving credit facility are secured by first
priority liens on substantially all of our West Texas assets and
are guaranteed by our subsidiaries.
At February 28, 2010, we had $37.9 million outstanding
under our revolving credit facility, with a weighted average
interest rate of 3.42%.
Covenants
Our credit agreement contains two principal financial covenants:
|
|
|
|
|
a consolidated modified current ratio covenant that requires us
to maintain a ratio of not less than 1.0 to 1.0 at all times.
The consolidated modified current ratio is calculated by
dividing Consolidated Current Assets (as defined in the credit
agreement) by Consolidated Current Liabilities (as defined in
the credit agreement). As defined more specifically in the
credit agreement, the consolidated modified current ratio is
calculated as current assets less current unrealized gains on
commodity derivatives plus the available borrowing base at the
respective balance sheet date, divided by current liabilities
less current unrealized losses on commodity derivatives at the
respective balance sheet date.
|
|
|
|
a consolidated funded debt to consolidated EBITDAX ratio
covenant that requires us to maintain a ratio of not more than
3.5 to 1.0 at the end of each fiscal quarter. The consolidated
funded debt to consolidated EBITDAX ratio is calculated by
dividing Consolidated Funded Debt (as defined in the credit
agreement) by Consolidated EBITDAX (as defined in the credit
agreement). As defined more specifically in the credit
agreement, consolidated EBITDAX is calculated as net income
(loss), plus (1) exploration expense, (2) depletion,
depreciation and amortization expense, (3) share-based
compensation expense, (4) unrealized loss on commodity
derivatives, (5) interest expense, (6) income and
franchise taxes and (7) certain other non-cash expenses,
less (1) gains or losses from sales or dispositions of
assets, (2) unrealized gain on commodity derivatives and
(3) extraordinary or non-recurring gains. For purposes of
calculating this ratio, consolidated EBITDAX for a fiscal
quarter is annualized pursuant to the credit agreement.
|
F-21
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Our credit agreement also restricts cash dividends and other
restricted payments, transactions with affiliates, incurrence of
other debt, consolidations and mergers, the level of operating
leases, assets sales, investments in other entities and liens on
properties.
In addition, our credit agreement contains customary events of
default that would permit our lenders to accelerate the debt
under our credit agreement if not cured within applicable grace
periods, including, among others, failure to make payments of
principal or interest when due, materially incorrect
representations and warranties, failure to make mandatory
prepayments in the event of borrowing base deficiencies, breach
of covenants, defaults upon other obligations in excess of
$500,000, events of bankruptcy, the occurrence of one or more
unstayed judgments in excess of $500,000 not covered by an
acceptable policy of insurance, failure to pay any obligation in
excess of $500,000 owed under any derivatives transaction or in
any amount if the obligation under the derivatives transaction
is secured by collateral under the credit agreement, any event
of default by the Company occurs under any agreement entered
into in connection with a derivatives transaction, liens
securing the loans under the credit agreement cease to be in
place, a Change in Control (as more specifically defined in the
credit agreement) of the Company occurs, and dissolution of the
Company.
At December 31, 2009, we were in compliance with all of our
covenants and had not committed any acts of default under the
credit agreement.
|
|
5.
|
Share-Based
Compensation
|
In June 2007, the board of directors and stockholders approved
the 2007 Stock Incentive Plan (the 2007 Plan). Under
the 2007 Plan, we may grant restricted stock, stock options,
stock appreciation rights, restricted stock units, performance
awards, unrestricted stock awards and other incentive awards.
The 2007 Plan reserves 10 percent of our outstanding common
shares as adjusted on January 1 of each year, plus shares of
common stock that were available for grant of awards under our
prior plan. Awards of any stock options are to be priced at not
less than the fair market value at the date of the grant. The
vesting period of any stock award is to be determined by the
board or an authorized committee at the time of the grant. The
term of each stock option is to be fixed at the time of grant
and may not exceed 10 years. Shares issued upon stock
options exercised are issued as new shares.
Share-based compensation expense amounted to $1.8 million,
$1.1 million and $4.6 million for the years ended
December 31, 2009, 2008 and 2007, respectively. Such
amounts represent the estimated fair value of stock awards for
which the requisite service period elapsed during the years.
The fair value of each option granted was estimated using an
option-pricing model with the following weighted average
assumptions during the years ended December 31, 2008 and
2007. There were no stock option grants during the year ended
December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
Expected dividends
|
|
|
|
|
|
|
|
|
Expected volatility
|
|
|
64
|
%
|
|
|
68
|
%
|
Risk-free interest rate
|
|
|
2.7
|
%
|
|
|
3.9
|
%
|
Expected life
|
|
|
6 years
|
|
|
|
6 years
|
|
We have not paid out dividends historically, thus the dividend
yields are estimated at zero percent.
Since our shares were not publicly traded prior to the IPO on
November 8, 2007, we used an average of historical
volatility rates based upon other companies within our industry
for awards in 2008 and 2007. Management believes that these
average historical volatility rates are currently the best
available indicator of expected volatility.
F-22
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The risk-free interest rate is the implied yield available for
zero-coupon U.S. government issues with a remaining term of
five years.
The expected lives of our options are determined based on the
term of the option using the simplified method outlined in Staff
Accounting Bulletin 110.
Assumptions are reviewed each time there is a new grant and may
be impacted by actual fluctuation in our stock price, movements
in market interest rates and option terms. The use of different
assumptions produces a different fair value for the options
granted or modified and impacts the amount of compensation
expense recognized on the consolidated statement of operations.
The following table summarizes stock options outstanding and
activity as of and for the years ended December 31, 2009,
2008 and 2007, (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Shares
|
|
|
Weighted
|
|
|
Remaining
|
|
|
|
|
|
|
Subject to
|
|
|
Average
|
|
|
Contractual
|
|
|
Aggregate
|
|
|
|
Stock
|
|
|
Exercise
|
|
|
Term
|
|
|
Intrinsic
|
|
|
|
Options
|
|
|
Price
|
|
|
(in years)
|
|
|
Value
|
|
|
Outstanding at January 1, 2007
|
|
|
346,155
|
|
|
$
|
3.33
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
205,950
|
|
|
$
|
12.05
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(72,114
|
)
|
|
$
|
3.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
479,991
|
|
|
$
|
7.07
|
|
|
|
8.02
|
|
|
$
|
2,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
74,345
|
|
|
$
|
14.90
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(63,459
|
)
|
|
$
|
3.33
|
|
|
|
|
|
|
|
|
|
Canceled
|
|
|
(56,575
|
)
|
|
$
|
12.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
434,302
|
|
|
$
|
8.47
|
|
|
|
7.34
|
|
|
$
|
837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Canceled
|
|
|
(24,975
|
)
|
|
$
|
12.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009
|
|
|
409,327
|
|
|
$
|
8.03
|
|
|
|
6.10
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable (fully vested) at December 31, 2009
|
|
|
320,480
|
|
|
$
|
6.52
|
|
|
|
5.56
|
|
|
$
|
385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair market value of the stock options granted during the
years ended December 31, 2008 and 2007 was $8.96 per share
and $7.69 per share, respectively. Total unrecognized
share-based compensation expense from unvested stock options as
of December 31, 2009 was $529,000, and will be recognized
over a remaining service period of 1.25 years. The
intrinsic value of the options exercised during the years ended
December 31, 2008 and 2007 was $770,000 and $634,000,
respectively. There was no tax benefit recognized in relation to
the stock options exercised.
F-23
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Share grants totaling 204,790, 35,948 and 411,041 shares
with an approximate aggregate market value of $1.7 million,
$733,000 and $5.2 million at the time of grant were granted
to employees during the years ended December 31, 2009, 2008
and 2007, respectively. The tax benefit recognized in relation
to the vested shares was $86,000. A summary of the status of
non-vested shares for the years ended December 31, 2009,
2008 and 2007, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Grant-Date
|
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Nonvested at January 1, 2007
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
411,041
|
|
|
|
12.70
|
|
Vested
|
|
|
(368,541
|
)
|
|
|
12.26
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2007
|
|
|
42,500
|
|
|
|
16.50
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
35,948
|
|
|
|
20.39
|
|
Vested
|
|
|
(21,250
|
)
|
|
|
16.50
|
|
Canceled
|
|
|
(1,175
|
)
|
|
|
15.48
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2008
|
|
|
56,023
|
|
|
$
|
18.96
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
204,790
|
|
|
$
|
8.40
|
|
Vested
|
|
|
(32,182
|
)
|
|
|
18.07
|
|
Canceled
|
|
|
(2,751
|
)
|
|
|
12.39
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2009
|
|
|
225,880
|
|
|
$
|
9.73
|
|
|
|
|
|
|
|
|
|
|
The unrecognized compensation of $896,000 related to the
nonvested shares will be recognized over a remaining service
period of 2.83 years.
Our (benefit) provision for income taxes comprised the following
during the years ended December 31, 2009, 2008 and 2007 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
|
|
|
$
|
(214
|
)
|
|
$
|
188
|
|
State
|
|
|
|
|
|
|
177
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
$
|
|
|
|
$
|
(37
|
)
|
|
$
|
188
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(1,056
|
)
|
|
$
|
11,919
|
|
|
$
|
(296
|
)
|
State
|
|
|
271
|
|
|
|
229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred
|
|
$
|
(785
|
)
|
|
$
|
12,148
|
|
|
$
|
(296
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Benefit) provision for income taxes
|
|
$
|
(785
|
)
|
|
$
|
12,111
|
|
|
$
|
(108
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-24
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Total income tax (benefit) expense differed from the amounts
computed by applying the U.S. Federal statutory tax rates
to pre-tax income for the years ended December 31, 2009,
2008 and 2007, as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Statutory tax at 34%
|
|
$
|
(2,045
|
)
|
|
$
|
12,069
|
|
|
$
|
884
|
|
State taxes, net of federal impact
|
|
|
72
|
|
|
|
199
|
|
|
|
29
|
|
Permanent differences(1)
|
|
|
231
|
|
|
|
235
|
|
|
|
609
|
|
Other differences(2)
|
|
|
957
|
|
|
|
(392
|
)
|
|
|
(35
|
)
|
Change in valuation allowance
|
|
|
|
|
|
|
|
|
|
|
(1,595
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(785
|
)
|
|
$
|
12,111
|
|
|
$
|
(108
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amount primarily relates to share-based compensation expense for
the years ended December 31, 2009 and 2008, and the
beneficial conversion feature on the convertible notes for the
year ended December 31, 2007. |
|
(2) |
|
Approximately $600,000 relates to a change in our estimated
income tax for the year ended December 31, 2008. |
Deferred tax assets and liabilities are the result of temporary
differences between the financial statement carrying values and
tax bases of assets and liabilities. Our net deferred tax assets
and liabilities are recorded as a long-term liability of
$38.4 million and $35.9 million at December 31,
2009 and 2008, respectively. At December 31, 2009, $255,000
of deferred taxes expected to be realized during 2010 was
included in current assets within prepaid expenses and other
current assets. Significant components of net deferred tax
assets and liabilities are (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
7,214
|
|
|
$
|
2,363
|
|
Unrealized loss on commodity derivatives
|
|
|
301
|
|
|
|
|
|
Other
|
|
|
362
|
|
|
|
694
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
$
|
7,877
|
|
|
$
|
3,057
|
|
Deferred tax liability:
|
|
|
|
|
|
|
|
|
Difference in depreciation, depletion and capitalization
methods oil and gas properties
|
|
|
(45,996
|
)
|
|
|
(38,948
|
)
|
Unrealized gain on commodity derivatives
|
|
|
|
|
|
|
(2,770
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(45,996
|
)
|
|
|
(41,718
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax (liability)
|
|
$
|
(38,119
|
)
|
|
$
|
(38,661
|
)
|
|
|
|
|
|
|
|
|
|
F-25
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Net operating loss carryforwards for tax purposes have the
following expiration dates (in thousands):
|
|
|
|
|
Expiration Dates
|
|
Amounts
|
|
|
2024
|
|
$
|
1,523
|
|
2025
|
|
|
1,082
|
|
2026
|
|
|
2,594
|
|
2027
|
|
|
2,703
|
|
2028
|
|
|
1,308
|
|
2029
|
|
|
12,009
|
|
|
|
|
|
|
Total
|
|
$
|
21,219
|
|
|
|
|
|
|
At December 31, 2009, we had the following commodity
derivatives positions outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
$/MMBtu
|
Period
|
|
Monthly
|
|
Total
|
|
Fixed
|
|
NYMEX Henry Hub
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swaps 2010
|
|
|
150,000
|
|
|
|
1,800,000
|
|
|
$
|
5.85
|
|
Price swaps 2010
|
|
|
150,000
|
|
|
|
1,800,000
|
|
|
$
|
6.40
|
|
Price swaps 2010
|
|
|
100,000
|
|
|
|
1,200,000
|
|
|
$
|
6.36
|
|
WAHA basis differential
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps 2010
|
|
|
415,000
|
|
|
|
4,980,000
|
|
|
$
|
(0.71
|
)
|
Basis swaps 2011
|
|
|
300,000
|
|
|
|
3,600,000
|
|
|
$
|
(0.53
|
)
|
The following summarizes the fair value of our open commodity
derivatives as of December 31, 2009 and December 31,
2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
Liability Derivatives
|
|
|
|
|
Fair Value
|
|
|
|
Fair Value
|
|
|
Balance Sheet
|
|
December 31,
|
|
December 31,
|
|
Balance Sheet
|
|
December 31,
|
|
December 31,
|
|
|
Location
|
|
2009
|
|
2008
|
|
Location
|
|
2009
|
|
2008
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives
|
|
Unrealized gain on
commodity derivatives
|
|
$
|
786
|
|
|
$
|
8,017
|
|
|
Unrealized loss on
commodity derivatives
|
|
$
|
2,668
|
|
|
$
|
|
|
The following summarizes the change in the fair value of our
commodity derivatives (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
Income Statement Location
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
Unrealized (loss) gain on commodity derivatives
|
|
$
|
(9,899
|
)
|
|
$
|
7,149
|
|
|
$
|
(3,637
|
)
|
|
|
Realized gain on commodity derivatives
|
|
|
14,659
|
|
|
|
2,936
|
|
|
|
4,732
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
4,760
|
|
|
$
|
10,085
|
|
|
$
|
1,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-26
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Unrealized gains and losses, at fair value, are included on our
consolidated balance sheets as current or non-current assets or
liabilities based on the anticipated timing of cash settlements
under the related contracts. Changes in the fair value of our
commodity derivative contracts are recorded in earnings as they
occur and included in other income (expense) on our consolidated
statements of operations. We estimate the fair values of swap
contracts based on the present value of the difference in
exchange-quoted forward price curves and contractual settlement
prices multiplied by notional quantities. We internally valued
the collar contracts using industry-standard option pricing
models and observable market inputs. We use our internal
valuations to determine the fair values of the contracts that
are reflected on our consolidated balance sheets. Realized gains
and losses are also included in other income (expense) on our
consolidated statements of operations.
We are exposed to credit losses in the event of nonperformance
by the counterparties on our commodity derivatives positions and
have considered the exposure in our internal valuations.
However, we do not anticipate nonperformance by the
counterparties over the term of the commodity derivatives
positions.
To estimate the fair value of our commodity derivatives
positions, we use market data or assumptions that market
participants would use in pricing the asset or liability,
including assumptions about risk and the risks inherent in the
inputs to the valuation technique. These inputs can be readily
observable, market corroborated or generally unobservable. We
primarily apply the market approach for recurring fair value
measurements and attempt to use the best available information.
We determine the fair value based upon the hierarchy that
prioritizes the inputs used to measure fair value. The hierarchy
gives the highest priority to unadjusted quoted prices in active
markets for identical assets or liabilities (Level 1
measurement) and lowest priority to unobservable inputs
(Level 3 measurement). The three levels of fair value
hierarchy are as follows:
|
|
|
|
|
Level 1 Quoted prices are available in active
markets for identical assets or liabilities as of the reporting
date. At December 31, 2009, we had no Level 1
measurements.
|
|
|
|
Level 2 Pricing inputs are other than quoted
prices in active markets included in Level 1, which are
either directly or indirectly observable as of the reporting
date. Level 2 includes those financial instruments that are
valued using models or other valuation methodologies. These
models are primarily industry-standard models that consider
various assumptions, including quoted forward prices for
commodities, time value, volatility factors and current market
and contractual prices for the underlying instruments, as well
as other relevant economic measures. Our derivatives, which
consist primarily of commodity swaps and collars, are valued
using commodity market data which is derived by combining raw
inputs and quantitative models and processes to generate forward
curves. Where observable inputs are available, directly or
indirectly, for substantially the full term of the asset or
liability, the instrument is categorized in Level 2. At
December 31, 2009, all of our commodity derivatives were
valued using Level 2 measurements.
|
|
|
|
Level 3 Pricing inputs include significant
inputs that are generally less observable from objective
sources. These inputs may be used with internally developed
methodologies that result in managements best estimate of
fair value. At December 31, 2009, our Level 3
measurements were limited to our asset retirement obligation.
|
On June 25, 2007, Yorktown Energy Partners VII, L.P. and
Lubar Equity Fund, LLC loaned an aggregate of $20 million
to AOG under two convertible promissory notes of
$10 million each. These notes bore interest at a rate of
7.00% per annum and had a maturity date of June 25, 2010,
at which time all principal and interest would have been due.
These notes were initially convertible at the election of the
lender into shares of equity securities of AOG at $100 per share
on December 31, 2007, or earlier if we sold substantially
all of the assets of AOG. Upon consummation of our IPO, the
notes automatically, and without further action required by any
person, converted into shares of ARI common stock. The number of
shares of ARI common stock
F-27
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
issued upon the automatic conversion of these notes was equal to
the quotient obtained by dividing (a) the outstanding
principal and accrued interest on each respective note by
(b) the IPO price per share, less any underwriting discount
per share for the shares of ARI common stock that were issued in
our IPO. The shares of our common stock issued to Yorktown
Energy Partners VII, L.P. and Lubar Equity Fund, LLC upon such
automatic conversion are entitled to the same registration
rights as those provided to certain holders of our common stock
in connection with the contribution agreement. The total
principal and interest owed under these notes at the time of the
IPO was $20.5 million. Yorktown Energy Partners VII, L.P.
is an affiliate of Yorktown Partners LLC, which has one
representative, Bryan H. Lawrence, who serves as a member of our
board of directors. Lubar Equity Fund, LLC is an affiliate of
Sheldon B. Lubar, who serves as a member of our board of
directors.
The automatic conversion of the notes into shares of ARI common
stock upon the closing of our IPO constituted a contingent
beneficial conversion feature because the price per share into
which these notes were convertible was less than the price paid
by other parties acquiring ARI common stock. Immediately upon
the closing of our IPO, we were required to measure the
intrinsic value of the beneficial conversion feature and record
such value as a charge to interest expense. The value of the
beneficial conversion feature, and therefore the amount of
interest expense, that was recognized when the notes were
converted on the date of the IPO, was $1.5 million.
|
|
9.
|
Canadian
Unconventional Gas Investment
|
In May 2007, we acquired shares of common stock of a
Canadian-based private exploration company focused on tight gas
and shale gas opportunities in Canada. Our investment amounted
to approximately $917,000 and is a non-controlling interest
accounted for using the cost method. We have written off the
carrying value of our minority equity investment in the Canadian
operator by recognizing a non-cash charge to earnings because we
believe we will not recover our investment.
|
|
10.
|
Commitments
and Contingencies
|
We have employment agreements with two of our officers. These
agreements are automatically renewed for successive terms of one
year unless employment is terminated at the end of the term by
written notice given to the employee not less than 60 days
prior to the end of such term. Our maximum commitment under the
employment agreements, which would apply if the employees
covered by these agreements were all terminated without cause,
is approximately $700,000 at December 31, 2009.
We lease our office space in Fort Worth, Texas, under a
non-cancelable agreement that expires on December 31, 2012.
In addition, we had a lease on our former office space that
expired in May 2009. We had sublease agreements for the former
office space that provided for a recovery of a substantial
portion of those rentals.
We also have non-cancelable operating lease commitments related
to office equipment that expire by 2012. The following is a
schedule by years of future minimum rental payments required
under our operating lease arrangements, net of minimum rentals
to be received under non-cancelable subleases as of
December 31, 2009 (in thousands):
|
|
|
|
|
2010
|
|
$
|
410
|
|
2011
|
|
|
419
|
|
2012
|
|
|
353
|
|
|
|
|
|
|
Total
|
|
$
|
1,182
|
|
|
|
|
|
|
Rent expense under our lease arrangements amounted to $461,000,
$299,000 and $198,000 for the years ended December 31,
2009, 2008 and 2007, respectively.
F-28
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Litigation
Approach Operating, LLC v. EnCana Oil & Gas
(USA) Inc., Cause No. 29.070A, District Court of
Limestone County, Texas. On July 2, 2009 our operating
subsidiary filed a lawsuit against EnCana EnCana Oil &
Gas (USA) Inc., or EnCana, for breach of the JOA covering our
North Bald Prairie project in East Texas and seeking damages for
nonpayment of amounts owed under the joint operating agreement,
or JOA, as well as declaratory relief. We contend that such
amounts owed by EnCana are at least $2.1 million, plus
attorneys fees, costs and other amounts to which we might
be entitled under law or in equity. The amount owed to us is
included in other non-current assets on our balance sheet at
December 31, 2009. As we previously have disclosed, in
December 2008, EnCana notified us that it was exercising its
right to become operator of record for joint interest wells in
North Bald Prairie under an operator election agreement between
the parties. EnCana contends that it does not owe us for part or
all of joint interest billings incurred after EnCana provided us
with notice of EnCanas election to assume operatorship in
December 2008. EnCana also contends that certain of the disputed
operations were unnecessary, while other charges are improper
because we failed to obtain EnCanas consent under the JOA
prior to undertaking the operations. We have informed the Court
that we will transfer operatorship to EnCana when EnCana has
made all payments it owes under the JOA.
We also are involved in various other legal and regulatory
proceedings arising in the normal course of business. While we
cannot predict the outcome of these proceedings with certainty,
we do not believe that an adverse result in any pending legal or
regulatory proceeding, individually or in the aggregate, would
be material to our consolidated financial condition or cash
flows; however, an unfavorable outcome could have a material
adverse effect on our results of operations for a specific
interim period or year.
Environmental
Issues
We are engaged in oil and gas exploration and production and may
become subject to certain liabilities as they relate to
environmental clean up of well sites or other environmental
restoration procedures as they relate to the drilling of oil and
gas wells and the operation thereof. In connection with our
acquisition of existing or previously drilled well bores, we may
not be aware of what environmental safeguards were taken at the
time such wells were drilled or during such time the wells were
operated. Should it be determined that a liability exists with
respect to any environmental clean up or restoration, we would
be responsible for curing such a violation. No claim has been
made, nor are we aware of any liability that exists, as it
relates to any environmental clean up, restoration or the
violation of any rules or regulations relating thereto.
F-29
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
11.
|
Oil and
Gas Producing Activities
|
Set forth below is certain information regarding the costs
incurred for oil and gas property acquisition, development and
exploration activities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
1,081
|
|
|
$
|
2,695
|
|
|
$
|
5,480
|
|
Proved properties
|
|
|
57
|
|
|
|
12,189
|
|
|
|
59,594
|
|
Exploration costs
|
|
|
1,483
|
|
|
|
5,007
|
|
|
|
9,897
|
|
Development costs(1)
|
|
|
28,121
|
|
|
|
84,193
|
|
|
|
37,451
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
30,742
|
|
|
$
|
104,084
|
|
|
$
|
112,422
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
For the years ended December 31, 2009 and 2008, development
costs include $170,000 and $3.5 million in non-cash asset
retirement obligations, respectively. |
Set forth below is certain information regarding the results of
operations for oil and gas producing activities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Revenues
|
|
$
|
40,648
|
|
|
$
|
79,869
|
|
|
$
|
39,114
|
|
Production costs
|
|
|
(9,773
|
)
|
|
|
(11,823
|
)
|
|
|
(5,474
|
)
|
Exploration expense
|
|
|
(1,621
|
)
|
|
|
(1,478
|
)
|
|
|
(883
|
)
|
Impairment
|
|
|
(2,964
|
)
|
|
|
(6,379
|
)
|
|
|
(267
|
)
|
Depletion
|
|
|
(24,660
|
)
|
|
|
(23,338
|
)
|
|
|
(13,010
|
)
|
Income tax expense
|
|
|
(554
|
)
|
|
|
(12,529
|
)
|
|
|
(6,623
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
1,076
|
|
|
$
|
24,322
|
|
|
$
|
12,857
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12.
|
Disclosures
About Oil and Gas Producing Activities (unaudited)
|
Proved
Reserves
The estimates of proved reserves and related valuations for the
years ended December 31, 2009, 2008 and 2007 were prepared
by DeGolyer and MacNaughton, independent petroleum engineers.
Each years estimate of proved reserves and related
valuations were also prepared in accordance with then-current
provisions of ASC 932 and Statement of Financial Accounting
Standards 69, or SFAS 69, Disclosures about Oil and Gas
Producing Activities.
F-30
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Estimates of proved reserves are inherently imprecise and are
continually subject to revision based on production history,
results of additional exploration and development, price changes
and other factors. All of our estimated oil and natural gas
reserves are attributable to properties within the United
States. A summary of Approachs changes in quantities of
proved oil and natural gas reserves for the years ended
December 31, 2007, 2008 and 2009, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed and Proved
|
|
Natural Gas
|
|
Oil & NGLs
|
|
Total
|
Undeveloped Reserves
|
|
(MMcf)
|
|
(MBbls)
|
|
(MMcfe)
|
|
BalanceDecember 31, 2006
|
|
|
98,657
|
|
|
|
1,122
|
|
|
|
105,389
|
|
Extensions and discoveries
|
|
|
36,194
|
|
|
|
1,807
|
|
|
|
47,036
|
|
Purchases of minerals in place
|
|
|
40,174
|
|
|
|
378
|
|
|
|
42,442
|
|
Production
|
|
|
(4,801
|
)
|
|
|
(84
|
)
|
|
|
(5,305
|
)
|
Revisions to previous estimates
|
|
|
(9,073
|
)
|
|
|
(15
|
)
|
|
|
(9,162
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BalanceDecember 31, 2007
|
|
|
161,151
|
|
|
|
3,208
|
|
|
|
180,400
|
|
Extensions and discoveries
|
|
|
22,879
|
|
|
|
3,228
|
|
|
|
42,249
|
|
Purchases of minerals in place
|
|
|
7,312
|
|
|
|
67
|
|
|
|
7,711
|
|
Production
|
|
|
(7,092
|
)
|
|
|
(277
|
)
|
|
|
(8,755
|
)
|
Revisions to previous estimates
|
|
|
(11,383
|
)
|
|
|
141
|
|
|
|
(10,537
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BalanceDecember 31, 2008
|
|
|
172,867
|
|
|
|
6,367
|
|
|
|
211,068
|
|
Extensions and discoveries
|
|
|
14,301
|
|
|
|
2,682
|
|
|
|
30,395
|
|
Purchases of minerals in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(6,320
|
)
|
|
|
(415
|
)
|
|
|
(8,808
|
)
|
Revisions to previous estimates
|
|
|
(12,514
|
)
|
|
|
(202
|
)
|
|
|
(13,727
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BalanceDecember 31, 2009
|
|
|
168,334
|
|
|
|
8,432
|
|
|
|
218,928
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
70,251
|
|
|
|
1,268
|
|
|
|
77,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
84,217
|
|
|
|
3,014
|
|
|
|
102,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
74,804
|
|
|
|
3,118
|
|
|
|
93,512
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following is a discussion of the material changes in our
proved reserve quantities for the years ended December 31,
2009, 2008 and 2007:
Year
Ended December 31, 2009
Our drilling programs in Cinco Terry and Ozona Northeast
resulted in our classification of reserves as proved, which
accounts for the additional quantities listed under extensions
and discoveries. For the year ended December 31, 2009, of
the 13,727 MMcfe downward revision of our previous
estimate, 10,152 MMcfe and 3,574 MMcfe relate to price
and performance revisions, respectively. The gas price used to
estimate our proved reserves decreased from $6.04 per Mcf at
December 31, 2008, to $3.88 per Mcf at December 31,
2009. The performance revision primarily related to producing
properties in our North Bald Prairie field in East Texas. Well
performance data collected during 2009 for North Bald Prairie
indicate that these assets underperformed our year-end 2008
decline estimates. Accordingly, we removed 4,514 MMcfe from
proved reserves recorded for North Bald Prairie. We also removed
620 MMcfe in Ozona Northeast due to performance revisions.
Partially offsetting the removal of 5,134 MMcfe from proved
reserves recorded for North Bald Prairie and Ozona Northeast was
a positive performance revision of 1,560 MMcfe in our Cinco
Terry field in West Texas.
F-31
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Year
Ended December 31, 2008
Our drilling programs in Ozona Northeast, Cinco Terry and North
Bald Prairie resulted in our classification of reserves as
proved, which accounts for the additional quantities listed
under extensions and discoveries. Additionally, during 2008 we
acquired 7,711 MMcfe of proved reserves in Ozona Northeast,
which accounts for the additional proved reserve quantities
listed as purchases of minerals in place. Downward revisions to
proved reserves of 7,405 MMcfe are the result of a
significant decline in commodity prices during the third and
fourth quarters of 2008. The gas price used to estimate our
proved reserves decreased from $8.10 per Mcf at
December 31, 2007 to $6.04 per Mcf at December 31,
2008. Downward revisions to proved reserves of 3,132 MMcfe,
which represents 1.7% of the our estimated proved reserves of
180,399 MMcfe at December 31, 2007, was based on the
accumulation of additional production results that occurred
during 2008 in Ozona Northeast and North Bald Prairie. Wells
that were primarily responsible for downward revisions had
little production history (as proved developed producing wells)
or no production history (as proved undeveloped locations) when
reserves for those wells and locations were booked at
December 31, 2007. At December 31, 2008, after
recording and reviewing a years worth of production
history, we determined to revise the estimated ultimate
recoveries for these wells downward.
Year
Ended December 31, 2007
Our drilling programs in Ozona Northeast, Cinco Terry and North
Bald Prairie resulted in our classification of reserves as
proved, which accounts for the additional quantities listed
under extensions and discoveries. Additionally, we completed the
acquisition of the Neo Canyon interest in Ozona Northeast
accounting for the additional quantities listed as purchases of
minerals in place. The downward revisions to proved reserves are
the result of performance in Ozona Northeast. Partially
offsetting the downward revisions was an increase in the average
gas price attributable to our proved reserves from $6.55 per Mcf
at December 31, 2006 to $8.10 per Mcf at December 31,
2007.
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved
Reserves
The standardized measure of discounted future net cash flows
relating to proved oil and natural gas reserves and the changes
in standardized measure of discounted future net cash flows
relating to proved oil and natural gas reserves were prepared in
accordance with then-current provisions of ASC 932 and
SFAS 69. Future cash inflows were computed by applying the
unweighted, arithmetic average on the closing price on the first
day of each month for the
12-month
period prior to December 31, 2009, to estimated future
production. Future production and development costs are computed
by estimating the expenditures to be incurred in developing and
producing the proved oil and natural gas reserves at year end,
based on year-end costs and assuming continuation of existing
economic conditions.
Future income tax expenses are calculated by applying
appropriate year-end tax rates to future pretax net cash flows
relating to proved oil and natural gas reserves, less the tax
basis of properties involved.
Future income tax expenses give effect to permanent differences,
tax credits and loss carryforwards relating to the proved oil
and natural gas reserves. Future net cash flows are discounted
at a rate of 10% annually to derive the standardized measure of
discounted future net cash flows. This calculation procedure
does not necessarily result in an estimate of the fair market
value of Approachs oil and natural gas properties.
F-32
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The standardized measure of discounted future net cash flows
relating to proved oil and natural gas reserves are as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Future cash flows
|
|
$
|
1,007,703
|
|
|
$
|
1,248,661
|
|
|
$
|
1,567,251
|
|
Future production costs
|
|
|
(358,276
|
)
|
|
|
(411,177
|
)
|
|
|
(401,579
|
)
|
Future development costs
|
|
|
(213,161
|
)
|
|
|
(201,259
|
)
|
|
|
(191,738
|
)
|
Future income tax expense
|
|
|
(88,796
|
)
|
|
|
(157,503
|
)
|
|
|
(285,384
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
347,470
|
|
|
|
478,722
|
|
|
|
688,550
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(267,479
|
)
|
|
|
(336,087
|
)
|
|
|
(472,590
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
79,991
|
|
|
$
|
142,635
|
|
|
$
|
215,960
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash flows as shown above were reported without
consideration for the effects of commodity derivative
transactions outstanding at each period end.
Changes
in Standardized Measure of Discounted Future Net Cash
Flows
The changes in the standardized measure of discounted future net
cash flows relating to proved oil and natural gas reserves are
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Balance, beginning of period
|
|
$
|
142,635
|
|
|
$
|
215,960
|
|
|
$
|
77,877
|
|
Net change in sales and transfer prices and in production
(lifting) costs related to future production
|
|
|
(89,649
|
)
|
|
|
(148,739
|
)
|
|
|
57,231
|
|
Changes in estimated future development costs
|
|
|
(29,647
|
)
|
|
|
(72,754
|
)
|
|
|
(39,506
|
)
|
Sales and transfers of oil and gas produced during the period
|
|
|
(30,877
|
)
|
|
|
(68,037
|
)
|
|
|
(33,640
|
)
|
Net change due to extensions, discoveries and improved recovery
|
|
|
26,648
|
|
|
|
58,249
|
|
|
|
107,864
|
|
Net change due to purchase of minerals in place
|
|
|
|
|
|
|
10,632
|
|
|
|
97,328
|
|
Net change due to revisions in quantity estimates
|
|
|
(12,034
|
)
|
|
|
(14,526
|
)
|
|
|
(21,001
|
)
|
Previously estimated development costs incurred during the period
|
|
|
28,121
|
|
|
|
89,942
|
|
|
|
28,026
|
|
Accretion of discount
|
|
|
18,743
|
|
|
|
29,369
|
|
|
|
12,843
|
|
Other
|
|
|
(3,449
|
)
|
|
|
(8,712
|
)
|
|
|
8,077
|
|
Net change in income taxes
|
|
|
29,500
|
|
|
|
51,251
|
|
|
|
(79,139
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
79,991
|
|
|
$
|
142,635
|
|
|
$
|
215,960
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The commodity prices in effect at December 31, 2009, 2008
and 2007 inclusive of adjustments for quality and location used
in determining future net revenues related to the standardized
measure calculation are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Oil (per Bbl)
|
|
$
|
56.04
|
|
|
$
|
39.60
|
|
|
$
|
93.30
|
|
Natural gas liquids (per Bbl)
|
|
$
|
27.20
|
|
|
$
|
23.00
|
|
|
$
|
60.09
|
|
Gas (per Mcf)
|
|
$
|
3.88
|
|
|
$
|
6.04
|
|
|
$
|
8.10
|
|
F-33
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Selected
Quarterly Financial Data (unaudited), (dollars in thousands,
except per-share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 Quarters Ended
|
|
|
|
December 31
|
|
|
September 30
|
|
|
June 30
|
|
|
March 31
|
|
|
Net revenue
|
|
$
|
11,881
|
|
|
$
|
8,787
|
|
|
$
|
9,915
|
|
|
$
|
10,065
|
|
Net operating expenses
|
|
|
(15,650
|
)
|
|
|
(10,715
|
)
|
|
|
(10,713
|
)
|
|
|
(12,557
|
)
|
Interest expense, net
|
|
|
(434
|
)
|
|
|
(451
|
)
|
|
|
(457
|
)
|
|
|
(445
|
)
|
Realized gain on commodity derivates
|
|
|
2,763
|
|
|
|
4,271
|
|
|
|
4,444
|
|
|
|
3,181
|
|
Unrealized (loss) gain on commodity derivatives
|
|
|
(1,310
|
)
|
|
|
(6,414
|
)
|
|
|
(4,320
|
)
|
|
|
2,145
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
|
(2,750
|
)
|
|
|
(4,522
|
)
|
|
|
(1,131
|
)
|
|
|
2,389
|
|
Income tax (benefit) provision
|
|
|
(468
|
)
|
|
|
(1,378
|
)
|
|
|
(460
|
)
|
|
|
1,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(2,282
|
)
|
|
$
|
(3,144
|
)
|
|
$
|
(671
|
)
|
|
$
|
868
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net (loss) income applicable to common stockholders per
common share
|
|
$
|
(0.11
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
0.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net (loss) income applicable to common stockholders per
common share
|
|
$
|
(0.11
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
0.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 Quarters Ended
|
|
|
|
December 31
|
|
|
September 30
|
|
|
June 30
|
|
|
March 31
|
|
|
Net revenue
|
|
$
|
14,692
|
|
|
$
|
22,015
|
|
|
$
|
24,144
|
|
|
$
|
19,018
|
|
Impairment of non-producing properties
|
|
|
(6,379
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net operating expenses
|
|
|
(14,485
|
)
|
|
|
(9,749
|
)
|
|
|
(11,855
|
)
|
|
|
(9,803
|
)
|
Interest expense, net
|
|
|
(355
|
)
|
|
|
(423
|
)
|
|
|
(343
|
)
|
|
|
(148
|
)
|
Impairment of investment
|
|
|
(917
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain (loss) on commodity derivates
|
|
|
3,612
|
|
|
|
(195
|
)
|
|
|
(542
|
)
|
|
|
61
|
|
Unrealized gain (loss) on commodity derivatives
|
|
|
3,089
|
|
|
|
18,611
|
|
|
|
(9,672
|
)
|
|
|
(4,879
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
|
(743
|
)
|
|
|
30,259
|
|
|
|
1,732
|
|
|
|
4,249
|
|
Income tax (benefit) provision
|
|
|
(591
|
)
|
|
|
10,411
|
|
|
|
804
|
|
|
|
1,487
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(152
|
)
|
|
$
|
19,848
|
|
|
$
|
928
|
|
|
$
|
2,762
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net (loss) income applicable to common stockholders per
common share
|
|
$
|
(0.01
|
)
|
|
$
|
0.96
|
|
|
$
|
0.04
|
|
|
$
|
0.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net (loss) income applicable to common stockholders per
common share
|
|
$
|
(0.01
|
)
|
|
$
|
0.95
|
|
|
$
|
0.04
|
|
|
$
|
0.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-34
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 Quarters Ended
|
|
|
|
December 31
|
|
|
September 30
|
|
|
June 30
|
|
|
March 31
|
|
|
Net revenue
|
|
$
|
11,740
|
|
|
$
|
8,292
|
|
|
$
|
9,690
|
|
|
$
|
9,392
|
|
Net operating expenses
|
|
|
(14,503
|
)
|
|
|
(5,644
|
)
|
|
|
(5,661
|
)
|
|
|
(6,581
|
)
|
Interest expense, net
|
|
|
(2,157
|
)
|
|
|
(1,108
|
)
|
|
|
(998
|
)
|
|
|
(956
|
)
|
Realized gain on commodity derivates
|
|
|
1,409
|
|
|
|
1,080
|
|
|
|
88
|
|
|
|
2,155
|
|
Unrealized (loss) gain on commodity derivatives
|
|
|
(1,520
|
)
|
|
|
785
|
|
|
|
1,724
|
|
|
|
(4,626
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
|
(5,031
|
)
|
|
|
3,405
|
|
|
|
4,843
|
|
|
|
(616
|
)
|
Income tax (benefit) provision
|
|
|
(3,238
|
)
|
|
|
1,312
|
|
|
|
1,853
|
|
|
|
(35
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,793
|
)
|
|
$
|
2,093
|
|
|
$
|
2,990
|
|
|
$
|
(581
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net (loss) income applicable to common stockholders per
common share
|
|
$
|
(0.12
|
)
|
|
$
|
0.22
|
|
|
$
|
0.32
|
|
|
$
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net (loss) income applicable to common stockholders per
common share
|
|
$
|
(0.12
|
)
|
|
$
|
0.20
|
|
|
$
|
0.29
|
|
|
$
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-35
Approach
Resources Inc.
Index to Exhibits
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description of Exhibit
|
|
|
3
|
.1
|
|
Restated Certificate of Incorporation of Approach Resources Inc.
(filed as Exhibit 3.1 to the Companys Quarterly Report on
Form 10-Q filed December 13, 2007 and incorporated herein by
reference).
|
|
3
|
.2
|
|
Restated Bylaws of Approach Resources Inc. (filed as Exhibit 3.2
to the Companys Quarterly Report on Form 10-Q filed
December 13, 2007 and incorporated herein by reference).
|
|
4
|
.1
|
|
Specimen Common Stock Certificate (filed as Exhibit 4.1 to the
Companys Registration Statement on Form S-1/A filed
October 18, 2007 (File No. 333-144512) and incorporated herein
by reference).
|
|
10
|
.1
|
|
Form of Indemnity Agreement between Approach Resources Inc. and
each of its directors and officers (filed as Exhibit 10.1 to the
Companys Registration Statement on Form S-1/A filed
September 13, 2007 (File No. 333-144512) and incorporated herein
by reference).
|
|
10
|
.2
|
|
First Amendment to Form of Indemnity Agreement between Approach
Resources Inc. and each of its directors and officers (filed as
Exhibit 10.5 to the Companys Current Report on Form 8-K
filed December 31, 2008 and incorporated herein by reference).
|
|
10
|
.3
|
|
Employment Agreement by and between Approach Resources Inc. and
J. Ross Craft dated January 1, 2003 (filed as Exhibit 10.3 to
the Companys Registration Statement on Form S-1 filed July
12, 2007 and incorporated herein by reference).
|
|
10
|
.4
|
|
First Amendment to Employment Agreement by and between Approach
Resources Inc. and J. Ross Craft dated December 31, 2008 (filed
as Exhibit 10.2 to the Companys Current Report on Form 8-K
filed December 31, 2008 and incorporated herein by reference).
|
|
10
|
.5
|
|
Employment Agreement by and between Approach Resources Inc. and
Steven P. Smart dated January 1, 2003 (filed as Exhibit 10.4 to
the Companys Registration Statement on Form S-1 filed July
12, 2007 and incorporated herein by reference).
|
|
10
|
.6
|
|
First Amendment to Employment Agreement by and between Approach
Resources Inc. and Steven P. Smart dated December 31, 2008
(filed as Exhibit 10.3 to the Companys Current Report on
Form 8-K filed December 31, 2008 and incorporated herein by
reference).
|
|
*10
|
.7
|
|
Separation Agreement by and between Approach Resources Inc. and
Glenn W. Reed dated November 10, 2009.
|
|
10
|
.8
|
|
Approach Resources Inc. 2007 Stock Incentive Plan, effective as
of June 28, 2007 (filed as Exhibit 10.6 to the Companys
Registration Statement on Form S-1 filed July 12, 2007 and
incorporated herein by reference).
|
|
10
|
.9
|
|
First Amendment dated December 31, 2008 to Approach Resources
Inc. 2007 Stock Incentive Plan, effective as of June 28, 2007
(filed as Exhibit 10.1 to the Companys Current Report on
Form 8-K filed December 31, 2008 and incorporated herein by
reference).
|
|
10
|
.10
|
|
Form of Business Opportunities Agreement among Approach
Resources Inc. and the other signatories thereto (filed as
Exhibit 10.11 to the Companys Registration Statement on
Form S-1/A filed October 18, 2007 (File No. 333-144512) and
incorporated herein by reference).
|
|
10
|
.11
|
|
Form of Option Agreement under 2003 Stock Option Plan (filed as
Exhibit 10.12 to the Companys Registration Statement on
Form S-1 filed July 12, 2007 and incorporated herein by
reference).
|
|
10
|
.12
|
|
Form of Summary of Stock Option Grant under Approach Resources
Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.14 to the
Companys Registration Statement on Form S-1/A filed
October 18, 2007 (File No. 333-144512) and incorporated herein
by reference).
|
|
10
|
.13
|
|
Restricted Stock Award Agreement by and between Approach
Resources Inc. and J. Curtis Henderson dated March 14, 2007
(filed as Exhibit 10.13 to the Companys Registration
Statement on Form S-1 filed July 12, 2007 and incorporated
herein by reference).
|
|
10
|
.14
|
|
Form of Stock Award Agreement under Approach Resources Inc. 2007
Stock Incentive Plan (filed as Exhibit 10.10 to the
Companys Quarterly Report on Form 10-Q filed November 6,
2008 and incorporated herein by reference).
|
66
Approach
Resources Inc.
Index to Exhibits (Continued)
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description of Exhibit
|
|
|
10
|
.15
|
|
Registration Rights Agreement dated as of November 14, 2007, by
and among Approach Resources Inc. and investors identified
therein (filed as Exhibit 10.1 to the Companys Current
Report on Form 8-K/A filed December 3, 2007 and incorporated
herein by reference).
|
|
10
|
.16
|
|
Gas Purchase Contract dated May 1, 2004 between Ozona Pipeline
Energy Company, as Buyer, and Approach Resources I, L.P.
and certain other parties identified therein (filed as Exhibit
10.18 to the Companys Registration Statement on Form S-1/A
filed September 13, 2007 (File No. 333-144512) and incorporated
herein by reference).
|
|
10
|
.17
|
|
Agreement Regarding Gas Purchase Contract dated May 26, 2006
between Ozona Pipeline Energy Company, as Buyer, and Approach
Resources I, L.P. and certain other parties identified
therein (filed as Exhibit 10.19 to the Companys
Registration Statement on Form S-1/A filed September 13, 2007
(File No. 333-144512) and incorporated herein by reference).
|
|
10
|
.18
|
|
Carry and Earning Agreement dated July 13, 2007 by and between
EnCana Oil & Gas (USA) (filed as Exhibit 10.22 to the
Companys Registration Statement on Form S-1/A filed
September 13, 2007 (File No. 333-144512) and incorporated herein
by reference).
|
|
10
|
.19
|
|
Oil & Gas Lease dated February 27, 2007 between the lessors
identified therein and Approach Oil & Gas Inc., as
successor to Lynx Production Company, Inc. (filed as Exhibit
10.23 to the Companys Registration Statement on Form S-1/A
filed September 13, 2007 (File No. 333-144512) and incorporated
herein by reference).
|
|
10
|
.20
|
|
Amendment dated as of January 1, 2009, to Oil & Gas Lease
dated February 27, 2007 between the lessors identified therein
and Approach Oil & Gas Inc., as successor to Lynx
Production Company, Inc. (filed as Exhibit 10.1 to the
Companys Current Report on Form 8-K filed October 14, 2009
and incorporated herein by reference).
|
|
10
|
.21
|
|
Specimen Oil and Gas Lease for Boomerang prospect between
lessors and Approach Oil & Gas Inc., as successor to The
Keeton Group, LLC, as lessee (filed as Exhibit 10.24 to the
Companys Registration Statement on Form S-1/A filed
September 13, 2007 (File No. 333-144512) and incorporated herein
by reference).
|
|
10
|
.22
|
|
Lease Crude Oil Purchase Agreement dated May 1, 2004 by and
between ConocoPhillips and Approach Operating LLC (filed as
Exhibit 10.26 to the Companys Registration Statement on
Form S-1/A
filed October 18, 2007 (File No. 333-144512) and incorporated
herein by reference).
|
|
10
|
.23
|
|
Gas Purchase Agreement dated as of November 21, 2007 between WTG
Benedum Joint Venture, as Buyer, and Approach Oil & Gas
Inc. and Approach Operating, LLC, as Seller (filed as Exhibit
10.1 to the Companys Current Report on Form 8-K filed
November 28, 2007 and incorporated herein by reference).
|
|
10
|
.24
|
|
$200,000,000 Revolving Credit Agreement dated as of January 18,
2008 among Approach Resources Inc., as borrower, The Frost
National Bank, as administrative agent and lender, and the
financial institutions named therein (filed as Exhibit 10.1 to
the Companys Current Report on Form 8-K filed January 25,
2008 and incorporated herein by reference).
|
|
10
|
.25
|
|
Amendment No. 1 dated February 19, 2008 to Credit Agreement
among Approach Resources Inc., as borrower, The Frost National
Bank, as administrative agent and lender, JPMorgan Chase Bank,
NA, as lender, and Approach Oil & Gas Inc., Approach Oil
& Gas (Canada) Inc. and Approach Resources I, LP, as
guarantors, dated as of January 18, 2008 (filed as Exhibit 10.1
to the Companys Current Report on Form 8-K filed February
22, 2008 and incorporated herein by reference).
|
|
10
|
.26
|
|
Amendment No. 2 dated May 6, 2008 to Credit Agreement among
Approach Resources Inc., as borrower, The Frost National Bank,
as administrative agent and lender, JPMorgan Chase Bank, NA, as
lender, and Approach Oil & Gas Inc., Approach Oil &
Gas (Canada) Inc. and Approach Resources I, LP, as
guarantors, dated as of January 18, 2008 (filed as Exhibit 99.1
to the Companys Current Report on Form 8-K filed August
28, 2008 and incorporated herein by reference).
|
67
Approach
Resources Inc.
Index to Exhibits (Continued)
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description of Exhibit
|
|
|
10
|
.27
|
|
Amendment No. 3 dated August 26, 2008 to Credit Agreement among
Approach Resources Inc., as borrower, The Frost National Bank,
as administrative agent and lender, JPMorgan Chase Bank, NA,
Fortis Capital Corp. and KeyBank National Association, as
lenders, and Approach Oil & Gas Inc., Approach Oil &
Gas (Canada) Inc. and Approach Resources I, LP, as
guarantors, dated as of January 18, 2008 (filed as Exhibit 10.1
to the Companys Current Report on Form 8-K filed August
28, 2008 and incorporated herein by reference).
|
|
10
|
.28
|
|
Amendment No. 4 dated April 8, 2009 to Credit Agreement among
Approach Resources Inc., as borrower, The Frost National Bank,
as administrative agent and lender, JPMorgan Chase Bank, NA,
Fortis Capital Corp. and KeyBank National Association, as
lenders, and Approach Oil & Gas Inc., Approach Oil &
Gas (Canada) Inc. and Approach Resources I, LP, as
guarantors, dated as of January 18, 2008 (filed as Exhibit 10.1
to the Companys Current Report on Form 8-K filed April 16,
2009 and incorporated herein by reference).
|
|
10
|
.29
|
|
Amendment No. 5 dated July 8, 2009 to Credit Agreement among
Approach Resources Inc., as borrower, The Frost National Bank,
as administrative agent and lender, JPMorgan Chase Bank, NA,
Fortis Capital Corp. and KeyBank National Association, as
lenders, and Approach Oil & Gas Inc., Approach Oil &
Gas (Canada) Inc. and Approach Resources I, LP, as
guarantors, dated as of January 18, 2008 (filed as Exhibit 10.1
to the Companys Current Report on Form 8-K filed July 14,
2009 and incorporated herein by reference).
|
|
10
|
.30
|
|
Amendment No. 6 dated as of October 30, 2009 to Credit Agreement
among Approach Resources Inc., as borrower, The Frost National
Bank, as administrative agent and lender, JPMorgan Chase Bank,
NA, Fortis Capital Corp. and KeyBank National Association, as
lenders, and Approach Oil & Gas Inc., Approach Oil &
Gas (Canada) Inc. and Approach Resources I, LP, as
guarantors, dated as of January 18, 2008 (filed as Exhibit 10.1
to the Companys Current Report on Form 8-K filed November
2, 2009 and incorporated herein by reference).
|
|
10
|
.31
|
|
Amendment No. 7 dated as of February 1, 2010 to Credit Agreement
dated as of January 18, 2008 among Approach Resources Inc., as
borrower, The Frost National Bank, as agent and lender, JPMorgan
Chase Bank, N.A., as successor agent and lender, Fortis Capital
Corp. and KeyBank National Association, as lenders, and Approach
Oil & Gas Inc., Approach Oil & Gas (Canada) Inc. and
Approach Resources I, LP, as guarantors (filed as Exhibit
10.1 to the Companys Current Report on Form 8-K filed
November 4, 2009 and incorporated herein by reference).
|
|
14
|
.1
|
|
Code of Conduct (filed as Exhibit 14.1 to the Companys
Annual Report on Form 10-K filed March 28, 2008 and incorporated
herein by reference).
|
|
*21
|
.1
|
|
Subsidiaries.
|
|
*23
|
.1
|
|
Consent of Hein & Associates LLP.
|
|
*23
|
.2
|
|
Consent of DeGolyer and MacNaughton.
|
|
*31
|
.1
|
|
Certification by the President and Chief Executive Officer
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
*31
|
.2
|
|
Certification by the Chief Financial Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.
|
|
*32
|
.1
|
|
Certification by the President and Chief Executive Officer
Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
*32
|
.2
|
|
Certification by the Chief Financial Officer Pursuant to U.S.C.
Section 1350, as adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
|
*99
|
.1
|
|
Report of DeGolyer and MacNaughton.
|
|
|
|
* |
|
Filed herewith. |
|
|
|
Denotes management contract or compensatory plan or arrangement. |
68