UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2010
or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 001-34224
Brigham Exploration Company
(Exact name of Registrant as Specified in its Charter)
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Delaware
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75-2692967 |
(State or other jurisdiction of
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(I.R.S. Employer |
incorporation or organization)
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Identification No.) |
6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730
(Address of principal executive offices) (Zip Code)
(512) 427-3300
(Registrants telephone number, including area code)
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 |
Common Stock, $0.01 par value
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NASDAQ Global Select Market |
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act. Yes þ No o
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 (§ 232.405 of this chapter) 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. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12-b of
the Act). Yes o No þ
As of June 30, 2010, the registrant had 116,596,688 shares of voting common stock outstanding.
The aggregate market value of the registrants outstanding shares of voting common stock held by
non-affiliates, based on the closing price of these shares on June 30, 2010 of $15.38 per share as
reported on The NASDAQ Global Select Market, was $1.7 billion. Shares held by each executive
officer and director and by each person who owns 10% or more of the outstanding common stock are
considered affiliates. The determination of affiliate status is not necessarily a conclusive
determination for other purposes.
As of February 23, 2011, the registrant had 116,968,942 shares of voting common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrants 2011 Annual Meeting of Stockholders
to be held on June 21, 2011, are incorporated by reference in Part III of this Form 10-K. Such
definitive proxy statement will be filed with the Securities and Exchange Commission not later than
120 days subsequent to December 31, 2010.
BRIGHAM EXPLORATION COMPANY
TABLE OF CONTENTS
BRIGHAM EXPLORATION COMPANY
2010 ANNUAL REPORT ON FORM 10-K
PART I
Overview
We are an independent exploration, development and production company that utilizes advanced
exploration, drilling and completion technologies to systematically explore for, develop and
produce domestic onshore crude oil and natural gas reserves. We focus our activities in provinces
where we believe these technologies, including horizontal drilling, multi-stage isolated fracture
stimulations and 3-D seismic imaging, can be used to effectively maximize our return on invested
capital.
Historically, our exploration and development activities have been focused in our Onshore Gulf
Coast, the Anadarko Basin and West Texas and Other provinces. However, in late 2007, the majority
of our drilling capital expenditures shifted from our historically active areas to the Williston
Basin, where we are currently targeting the Bakken, Three Forks and Red River objectives. As of
December 31, 2010, we had approximately 600,601 gross and 364,309 net leasehold acres in the
Williston Basin. Through year-end 2010, we have invested in excess of $625 million on drilling,
land and support infrastructure in this province.
At December 31, 2010, our proved reserves totaled 66.8 million barrels of oil equivalent
(MMBoe) and had a standardized measure of $866.1 million and a pre-tax PV10% value of $1.1 billion.
Approximately 78% of our proved reserves are crude oil and we operate approximately 81% of our
proved reserves. Our average production volumes for 2010 were 8,267 barrels of oil equivalent per
day (Boepd), which represents a 64% increase from 2009.
The following table provides information regarding our assets and operations located in our
core areas.
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At December 31, 2010 |
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2010 |
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Productive |
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Average |
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Proved |
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Pre-Tax |
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Wells |
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Daily Production |
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Province |
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Reserves(a) |
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PV10%(b)(c) |
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Oil |
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Gross |
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Net |
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Volumes (d) |
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(MMBoe) |
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(Millions) |
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(Boe) |
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Williston Basin |
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55.5 |
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$ |
939.4 |
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89 |
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237 |
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61.0 |
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6,146 |
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Onshore Gulf
Coast |
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7.6 |
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127.7 |
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21 |
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85 |
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44.5 |
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1,394 |
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Anadarko Basin |
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2.6 |
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22.1 |
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7 |
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89 |
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23.6 |
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558 |
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West Texas and Other |
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1.1 |
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19.5 |
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87 |
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31 |
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7.6 |
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169 |
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Total |
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66.8 |
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1,108.7 |
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78 |
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442 |
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136.7 |
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8,267 |
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(a) |
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MMBoe is defined as one million barrels of oil equivalent determined using the ratio of six
Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids. |
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The prices used to calculate this measure were $79.43 per barrel of crude oil and $4.376 per
MMbtu of natural gas. The prices represent the average prices per barrel of crude oil and per
MMbtu of natural gas at the beginning of each month in the 12-month period prior to the end of
the reporting period. These prices were adjusted to reflect applicable transportation and
quality differentials on a well-by-well basis to arrive at realized sales prices used to
estimate our reserves at this date. |
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The standardized measure for our proved reserves at December 31, 2010 was $866.1 million. See
Item 2. Properties Reconciliation of Standardized Measure to Pre-tax PV10% for a
definition of pre-tax PV10% and a reconciliation of our standardized measure to our pre-tax
PV10% value. |
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Average daily production volumes calculated based on 360 day year. Average daily production
volumes include approximately 29,654 barrels of oil produced during 2010 and recorded as
inventory at year-end 2010. Total oil inventory at year-end 2010 and 2009 was 46,129 and
16,475 barrels of crude oil, respectively. Total crude oil inventory at year-end 2008 was not
material. Adjusting production volumes for amounts included in inventory would result in
average daily sales volumes in 2010 and 2009 of 8,185 and 4,988 barrels of oil per day. |
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Since inception we have drilled and completed, or are currently in the process of drilling or
completing 1,075 gross wells, consisting of 525 exploration and 550 development wells with an
average completion rate of 77%. Over the three year period ended December 31, 2010, we drilled and
completed, or were in the process of drilling or completing 315 gross wells, consisting of 10
exploratory and 305 development wells with an average completion rate of 99%. Our improved
completion rate over the past three years is attributable to our increased level of activity in the
Williston Basin, which is an unconventional resource play that generally provides more predictable
drilling results. During 2010, we drilled and completed or were currently in the process of
drilling or completing 193 gross wells, consisting of one exploratory well and 192 development
wells with a completion rate of 100%. Both our higher levels of development drilling and completion
rate in 2010, as compared to prior years, are also attributable to our increased level of activity
in the Williston Basin.
Over the three year period ended December 31, 2010, we spent approximately $474.5 million on
drilling capital expenditures, $162.9 million on land, prior to proceeds from asset
sales, and $33.2 million on support infrastructure. Approximately 88% of our total drilling, land,
seismic and support infrastructure spending over this three year period, prior to proceeds from
asset sales, was spent in the Williston Basin.
In 2010, we spent approximately $280.1 million on drilling capital expenditures, which
represents a 381% increase from that in 2009. The increase was a result of our limited drilling
activity during the first half of 2009 as a result of the global financial recession that severely
depressed commodity prices. As economic conditions improved, we issued equity in October 2009 and
April 2010 to increase our operated drilling activity in the Williston Basin to four operated
drilling rigs by year-end 2009 and to seven operated drilling rigs by year-end 2010. This increase
in our operated drilling rig count resulted in higher levels of drilling capital expenditures
during 2010. In 2010, we spent approximately $113.5 million on land, prior to proceeds from asset sales, which represents a 1,002% increase from that in 2009. Our
higher level of land expenditures was primarily driven by the acquisition of approximately 81,725
net acres in the Williston Basin during 2010. In 2010, we spent approximately $33.2 million on
support infrastructure, which includes oil, natural gas, produced water and fresh water gathering
lines primarily in Williams and Mountrail Counties, North Dakota. We also drilled two water
disposal wells and began construction on a regional office in Williston, North Dakota. These
expenditures were incurred in order to more effectively and efficiently manage our rapidly growing
operations in the Williston Basin. In earlier periods, we did not incur material support
infrastructure costs.
In 2011, we anticipate spending approximately $582.1 million on drilling capital expenditures,
$27.4 million on land and $83.2 million on support infrastructure. The increase in our drilling
capital expenditure budget is a result of our continued acceleration of drilling activity in the
Williston Basin. We began 2011 with seven operated drilling rigs and anticipate adding an eighth
operated drilling rig in May 2011 and another operated drilling rig in September 2011. Further, our plans
are to add an additional operated rig every four months until we reach 12 rigs by September 2012.
Lower land and seismic costs are anticipated as acquisition activity is expected to be more
competitive in 2011 as compared to 2010. Our support infrastructure costs are anticipated to
increase in 2011, as we expand construction of gathering lines in Williams County and begin to construct gathering lines in McKenzie County,
North Dakota and drill additional water disposal wells.
Our 2011 budget is anticipated to be funded
with cash and short term investments on hand as of year-end 2010, cash flow from operations, the
proceeds from potential conventional oil and gas asset sales and availability under our Fifth
Amended and Restated Credit Agreement that closed on February 23, 2011, which had no amounts
outstanding and a $325 million borrowing base.
Business Strategy
Our business strategy is to create value for our stockholders by growing reserves, production
and cash flow utilizing advanced exploration, drilling and completion technologies to
systematically explore for, develop and produce domestic onshore crude oil and natural gas
reserves. Key elements of our business strategy include:
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Focus on Net Asset Value Creation in our Provinces. We plan to concentrate the majority
of our near term capital expenditures in the Williston Basin, where we believe our
approximately 364,309 net acres and the application of advanced drilling and completion
techniques provide us with a significant competitive advantage in developing the
significant net asset value associated with both the Bakken and Three Forks producing
horizons. In addition to the Williston Basin, we have a multi-year drilling prospect
inventory in
the following three provinces: Onshore Gulf Coast, Anadarko Basin and West Texas. Our
projects in these provinces provide us with important future drilling investment
diversification. |
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Leverage our Engineering and Operational Expertise. Our staff is highly proficient with
state-of-the-art drilling and completion techniques, including directional drilling,
horizontal drilling and multi-stage isolated fracture stimulations. Our drilling and
completion techniques in the Williston Basin have rapidly evolved from drilling and
completing long lateral wells with single large uncontrolled fracture stimulations in late
2006 to drilling and completing long lateral wells with 20 isolated fracture stimulation
stages in early 2009. During 2010, we typically drilled and completed our long lateral
wells with between 30 and 38 isolated fracture stimulation stages and made other changes to
our drilling and completion formula. We will continue to refine our drilling and completion
techniques in order to attempt to enhance the performance and the associated estimated
ultimate recoveries and net asset value of our wells. |
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Capitalize on Internally Generated Exploration Successes Through Disciplined
Development Activities. From 1990 to 1999, we grew our reserves and production volumes
primarily through successful exploration drilling. In recent years, our exploratory
drilling success has generated a multi-year inventory of development drilling locations. We
have a 20 year track record of successfully generating and drilling exploration wells in
new oil and natural gas plays. We are particularly interested in those plays with
attractive exploration and development potential that complement our current exploration,
development and production activities. After identifying such a play, we will often
selectively build an acreage position in the play. Our current inventory of drilling
locations in the Williston Basin and the Vicksburg and Hunton plays in our Onshore Gulf
Coast province are examples of successful projects where our position in the play was
internally identified and originated. |
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Enhance Returns Through Operational Control. We typically leverage our technical and
operational expertise by seeking to maintain operational control of our exploration and
drilling activities. As operator, we retain more control over the timing, selection and
process of drilling prospects, which enhances our ability to maximize our return on
invested capital. Since we generate most of our own projects, we generally have the ability
to retain operational control over all phases of our exploration, development and
production activities. Furthermore, retaining operational control gives us the ability to
control the financing, construction and operation of infrastructure related to our
production operations such as crude oil, natural gas and wastewater gathering and
processing, which in certain situations can enhance our well and project economics. |
Exploration and Land Staff
Our experienced exploration staff includes 12 geologists, five geophysicists, two computer
applications specialists and five geological technicians. Our geologists and geophysicists have
varied, but complementary backgrounds. Their diversity of experience in a wide-range of geological
and geophysical settings, combined with various technical specializations (from hardware and
systems to software and seismic data processing), provides us with valuable technical, intellectual
resources. Our geologists and geophysicists have an average of more than 20 years of experience in
the industry. We have assembled our team of geologists and geophysicists with backgrounds that
complement the areas where we focus our exploration and development activities. By integrating both
geologic and geophysical expertise within our project teams, we believe we possess a competitive
advantage in our exploration approach.
Our land department staff includes six landmen with an average of more than 17 years of
experience, primarily within our core provinces, and seven lease and division order analysts. Our
land department contributed to pioneering many of the innovations that have facilitated exploration
using large 3-D seismic projects.
Operations Staff
In an effort to retain better control of our project timing, drilling, operational costs and
production volumes, we attempt to operate as many of the wells we drill as possible. We operated
approximately 29% of the gross wells and 81% of the net wells that we drilled during 2010, as
compared with 10% of the gross wells and 17% of the net wells we drilled during 1996. In 2011, we
anticipate we will operate an increased number of wells as we currently have seven operated
drilling rigs running in the Williston Basin and, subject to commodity price risk, service costs
and
other factors, anticipate increasing our operated drilling rig count to nine rigs by September
2011. As a result of our increased operational control, wells operated by us constituted 81% of our
proved reserves at year-end 2010, as compared to only 5% at year-end 1996.
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Our operations staff includes ten engineers with an average of more than 13 years of
experience in drilling, reservoir, operations or environmental engineering primarily within our
four core operating provinces. These engineers work closely with our geologists and geophysicists
and are integrally involved in all phases of the exploration and development process, including
preparation of pre- and post-drill reserve estimates, well design, production management and
analysis of full cycle risked drilling economics. We conduct field operations for our operated oil
and natural gas properties through a combination of our field and third party contract personnel.
As of year-end 2010, we had three employees located in North Dakota and anticipate opening a
regional office in Williston, North Dakota in the second quarter 2011 in order to more effectively
and efficiently manage our operations in the Williston Basin.
Crude Oil and Natural Gas Market and Major Customers
In an effort to improve price realizations from the sale of our crude oil and natural gas, we
manage our commodities marketing activities in-house, which enables us to market and sell our crude
oil and natural gas to a broader universe of potential purchasers. Due to the availability of other
markets and pipeline connections, we do not believe that the loss of any single crude oil or
natural gas customer would have a material adverse effect on our results of operations or cash
flows.
We sell our crude oil
and condensate at the lease to a variety of purchasers at prevailing
market prices under short-term contracts that normally provide for us to receive a
market based
price, which incorporates regional differentials that include but are not limited to transportation
costs and adjustments for product quality. See Item 2. Properties
Delivery Commitments.
Our natural gas production is sold to various purchasers including intrastate pipeline
purchasers, operators of processing plants, and marketing companies under both monthly spot market
contracts and multi-year arrangements. The vast majority of our natural gas sales are based on
related natural gas index pricing. In some cases, our gas is processed at a plant and we receive a
percentage of the value the plant operator receives from the resale of the natural gas liquids
recovered and the remaining residue gas. See Item 2. Properties Delivery
Commitments.
Since most of our crude oil and natural gas production is sold under price sensitive or spot
market contracts, the revenues generated by our operations are highly dependent upon the prices of
and demand for crude oil and natural gas. The price we receive for our crude oil and natural gas
production depends upon numerous factors beyond our control, including but not limited to
seasonality, weather, competition, the condition of the United States economy, foreign imports,
political conditions in other crude oil-producing and natural gas-producing countries, the actions
of the Organization of Petroleum Exporting Countries, and domestic government regulation,
legislation and policies. See Item 1A. Risk Factors Crude oil and natural gas prices are
volatile and thus could be subject to further reduction, which would adversely affect our results
and the price of our common stock. Furthermore, a decrease in the price of crude oil and natural
gas could have an adverse effect on the carrying value of our proved reserves and on our revenues,
profitability and cash flow. See Item 1A. Risk Factors Lower crude oil and natural gas prices
may cause us to record ceiling limitation writedowns, which would reduce our stockholders equity.
Although we are not currently experiencing any significant involuntary curtailment of our
crude oil or natural gas production, market, economic and regulatory factors may in the future
materially affect our ability to sell our crude oil or natural gas production. See Item 1A. Risk
Factors The marketability of our crude oil and natural gas production depends on services and
facilities that we typically do not own or control. The failure or inaccessibility of any such
services or facilities could affect market based prices or result in a curtailment of production
and revenues.
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Competition
The oil and natural gas industry is highly competitive in all phases. We encounter competition
from other oil and natural gas companies in all areas of operation, including the acquisition of
seismic and leasing options on oil and natural gas properties to the exploration and development of
those properties. Our competitors include major integrated oil and natural gas companies, numerous
independent oil and natural gas companies, individuals and drilling and income programs. Many of
our competitors are large, well established companies that have substantially larger operating
staffs and greater capital resources than we do. Such companies may be able to pay more for seismic
and lease options on oil and natural gas properties and exploratory prospects and to define,
evaluate, bid for and purchase a greater number of properties and prospects than our financial or
human resources permit. Our ability to acquire additional properties and to discover reserves in
the future will depend upon our ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment. See Item 1A. Risk Factors We face
significant competition and many of our competitors have resources in excess of our available
resources.
Operating Hazards and Uninsured Risks
Drilling activities are subject to many risks, including the risk that no commercially
productive reservoirs will be encountered. There can be no assurance that the new wells we drill
will be productive or that we will recover all or any portion of our investment. Drilling for oil
and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that
are productive, but do not produce sufficient net revenues to return a profit after drilling,
operating and other costs. The cost and timing of drilling, completing and operating wells is often
uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which are beyond our control, including low crude oil and natural gas prices,
title problems, weather conditions, delays by project participants, compliance with governmental
requirements, shortages or delays in the delivery of equipment and services and increases in the
cost for such equipment and services. Our future drilling activities may not be successful and, if
unsuccessful, such failure may have a material adverse effect on our business, financial condition,
results of operations and cash flows. See Item 1A. Risk Factors Our exploration, development
and drilling efforts and the operation of our wells may not be profitable or achieve our targeted
returns, Item 1A. Risk Factors Exploratory drilling is a speculative activity that may not
result in commercially productive reserves and may require expenditures in excess of budgeted
amounts, Item 1A. Risk Factors Although our oil and natural gas reserve data is independently
estimated, these estimates may still prove to be inaccurate and Item 1A. Risk Factors The lack
of availability or high cost of drilling rigs, equipment, supplies, insurance, personnel and oil
field services could adversely affect our ability to execute our exploration and development plans
on a timely basis and within our budget.
Our operations are subject to hazards and risks inherent in drilling for and producing and
transporting crude oil and natural gas, such as fires, natural disasters, explosions, encountering
formations with abnormal pressures, blowouts, craterings, pipeline ruptures and spills, any of
which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and
other damage to our properties and those of others. We maintain insurance against some but not all
of the risks described above. In particular, the insurance we maintain does not cover claims
relating to failure of title to oil and natural gas leases, loss of surface equipment at well
locations, trespass during 3-D survey acquisition or surface damage attributable to seismic
operations, business interruption, loss of revenue due to low commodity prices or loss of revenues
due to well failure. Furthermore, in certain circumstances in which insurance is available, we may
not purchase it. The occurrence of an event that is not covered, or not fully covered by insurance
could have a material adverse effect on our business, financial condition, results of operations
and cash flows in the period such event may occur. See Item 1A. Risk Factors We are subject to
various operating and other casualty risks that could result in liability exposure or the loss of
production and revenues and Item 1A. Risk Factors We may not have enough insurance to cover
all of the risks we face, which could result in significant financial exposure.
Governmental Regulation
Our crude oil and natural gas exploration, production, transportation and marketing activities
are subject to extensive laws, rules and regulations promulgated by federal and state legislatures
and agencies, including but not limited to the Federal Energy Regulatory Commission (FERC), the
Environmental Protection Agency (EPA), the Bureau of Land Management (BLM), the Texas Commission on
Environmental Quality (TCEQ), the Texas Railroad Commission (TRRC), the Louisiana Department of
Natural Resources (LDNR), the Industrial Commission of North Dakota (NDIC), the Oklahoma
Corporation Commission (OCC), the Montana Board of Oil and Gas Conservation (MBOGC) and similar
type commissions within these states and of the other states in which we do business. Failure
to comply with such laws, rules and regulations can result in substantial penalties, including
the delay or stopping of our operations. The legislative and regulatory burden on the oil and
natural gas industry increases our cost of doing business and affects our profitability. See Item
1A. Risk Factors We are subject to various governmental regulations and environmental risks that
may cause us to incur substantial costs.
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Although we do not own or operate any pipelines or facilities that are directly regulated by
FERC, its regulation of third party pipelines and facilities could indirectly affect our ability to
transport or market our production. Moreover, FERC has in the past, and could in the future, impose
price controls on the sale of natural gas. We believe we are in substantial compliance with all
applicable laws and regulations; however, we are unable to predict the future cost or impact of
complying with such laws and regulations because they are frequently amended, interpreted and
reinterpreted.
The states of Texas, Oklahoma, Louisiana, North Dakota, Montana and most other states, as well
as the federal government when operating on federal or Indian lands, require permits for drilling
operations, drilling bonds and reports concerning operations and impose other requirements relating
to the exploration and production of crude oil and natural gas. These governmental authorities also
have statutes or regulations addressing conservation matters, including provisions for the
unitization or pooling of crude oil and natural gas properties, the establishment of maximum rates
of production from wells and the regulation of spacing, plugging and abandonment of such wells.
Environmental Matters
Our operations and properties are, like the oil and natural gas industry in general, subject
to extensive and changing federal, state and local laws and regulations relating to both
environmental protection, including the generation, storage, handling, emission, transportation and
discharge of materials into the environment, and safety and health. The recent trend in
environmental legislation and regulation is generally toward stricter standards, and this trend is
likely to continue. These laws and regulations may require a permit or other authorization before
construction or drilling commences and for certain other activities; limit or prohibit access,
seismic acquisition, construction, drilling and other activities on certain lands lying within
wilderness and other protected areas; impose substantial liabilities for pollution resulting from
our operations; and require the reclamation of certain lands.
The permits required for many of our operations are subject to revocation, modification and
renewal by issuing authorities. Governmental authorities have the power to enforce compliance with
their regulations, and violations are subject to fines, injunctions, or both. In the opinion of
management, we are in substantial compliance with current applicable environmental laws and
regulations, and we have no material commitments for capital expenditures to comply with existing
environmental requirements. Nevertheless, changes in existing environmental laws and regulations or
in interpretations thereof could have a significant impact on us, as well as the oil and natural
gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA) and comparable state statutes impose strict and arguably joint and several liabilities on
owners and operators of certain sites and on persons who disposed of or arranged for the disposal
of hazardous substances found at such sites. It is not uncommon for the 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. The Resource Conservation and Recovery Act
(RCRA) and comparable state statutes govern the disposal of solid waste and hazardous waste and
authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA
currently excludes petroleum from its definition of hazardous substance, state laws affecting our
operations impose clean-up liability relating to petroleum and petroleum related products. In
addition, although RCRA classifies certain oil field wastes as non-hazardous, such exploration
and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject
to more stringent handling and disposal requirements.
Federal regulations require certain owners or operators of facilities that store or otherwise
handle crude oil, such as us, to prepare and implement spill prevention, control countermeasure and
response plans relating to the possible discharge of crude oil into surface waters. The Oil
Pollution Act of 1990 (OPA) contains numerous requirements relating to the prevention of and
response to oil spills into waters of the United States. For onshore and offshore facilities that
may affect waters of the United States, the OPA requires an operator to demonstrate financial
responsibility. Regulations are currently being developed under federal and state laws concerning
oil pollution prevention and other matters that may impose additional regulatory burdens on us. In
addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize
discharge into surface waters or to construct facilities in wetland areas. The Clean Air Act of
1970 (CAA) and its subsequent amendments in 1990 and 1997 also
impose permit requirements and necessitate certain restrictions on point source emissions of
volatile organic carbons (nitrogen oxides and sulfur dioxide) and particulates with respect to
certain of our operations. We are required to maintain such permits or meet general permit
requirements. The EPA and designated state agencies have in place regulations concerning discharges
of storm water runoff and stationary sources of air emissions. These programs require covered
facilities to obtain individual permits, participate in a group or seek coverage under an EPA
general permit. Most agencies recognize the unique qualities of oil and natural gas exploration and
production operations. A number of agencies including but not limited to the EPA, the BLM, the
TCEQ, the LDNR, the NDIC, the OCC, the MBOGC and similar commissions within these states and of
other states in which we do business have adopted regulatory guidance in consideration of the
operational limitations on these types of facilities and their potential to emit pollutants. We
believe that we will be able to obtain, or be included under, such permits, where necessary, and to
make minor modifications to existing facilities and operations that would not have a material
effect on us.
7
In addition to the aforementioned regulatory agencies, there are various federal and state
programs that regulate conservation and development of coastal resources. The federal Coastal Zone
Management Act (CZMA) was passed to preserve and, where possible, restore the natural resources of
the United States coastal zone. The CZMA provides for federal grants for the state management
programs that regulate land use, water use and coastal development.
The Texas Coastal Coordination Act (CCA) provides for coordination among local and state
authorities to protect coastal resources through regulating land use, water, and coastal
development and establishes the Texas Coastal Management Program that applies in the nineteen
counties that border the Gulf of Mexico and its tidal bays. The CCA provides for the review of
state and federal agency rules and agency actions for consistency with the goals and policies of
the Coastal Management Plan. This review may affect agency permitting and may add a further
regulatory layer to some of our projects.
The Louisiana Coastal Zone Management Program (LCZMP) was established to protect, develop and,
where feasible, restore and enhance coastal resources of the state. Under the LCZMP, coastal use
permits are required for certain activities, even if the activity only partially infringes on the
coastal zone. Among other things, projects involving use of state lands and water bottoms, dredge
or fill activities that intersect with more than one body of water, mineral activities, including
the exploration and production of crude oil and natural gas, and pipelines for the gathering,
transportation or transmission of crude oil, natural gas and other minerals require such permits.
General permits, which entail a reduced administrative burden, are available for a number of
routine oil and gas activities. The LCZMP and its requirement to obtain coastal use permits may
result in additional permitting requirements and associated project schedule constraints.
See Item 1A. Risk Factors We are subject to various governmental regulations and
environmental risks that may cause us to incur substantial costs.
Climate Change
Climate change has become the subject of an important public policy debate. Climate change
remains a complex issue, with some scientific research suggesting that an increase in greenhouse
gas emissions (GHGs) may pose a risk to society and the environment. The oil and natural gas
exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane,
and future restrictions on the combustion of fossil fuels or the venting of natural gas could have
a significant impact on our future operations. See Item 1A. Risk Factors The adoption of
climate change legislation by Congress could result in increased operating costs and reduced demand
for the crude oil and natural gas we produce.
Impact of Legislation and Regulation. The commercial risk associated with the exploration and
production of fossil fuels lies in the uncertainty of government-imposed climate change
legislation, including cap and trade schemes, and regulations that may affect us, our suppliers,
and our customers. The cost of meeting these requirements may have an adverse impact on our
financial condition, results of operations and cash flows, and could reduce the demand for our
products.
Climate change legislation and regulations have been adopted by many states in the US.
However, legislation has not been enacted at the federal level in the US. The 111th Congress
considered a number of bills designed to regulate green house gas emissions, but did not pass any
of those bills. It is unclear whether the current Congress or a future Congress will take further
action on green house gasses. But, several states are considering adopting climate
change legislation. The current state of development of many state and federal climate change
regulatory initiatives in areas where we operate makes it difficult to predict with certainty the
future impact on us, including accurately estimating the related compliance costs that we may
incur.
8
Indirect Consequences of Regulation or Business Trends. We believe there are risks arising
from the global response to climate change. See Item 1A. Risk Factors The adoption of climate
change legislation by Congress could result in increased operating costs and reduced demand for the
crude oil and natural gas we produce.
Physical Impacts of Climate Change on our Costs and Operations. There has been public
discussion that climate change may be associated with extreme weather conditions such as more
intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels.
Extreme weather conditions increase our costs, and damage resulting from extreme weather may not be
fully insured. However, the extent to which climate change may lead to increased storm or weather
hazards affecting our operations is difficult to identify at this time.
Formation
We were incorporated in the State of Delaware on February 25, 1997.
Facilities
Our principal executive offices are located in Austin, Texas, where we lease approximately
36,621 square feet of office space at 6300 Bridge Point Parkway, Building 2, Suite 500, Austin,
Texas 78730. We also have a field office in Ross, North Dakota and plan to open a regional
office in Williston, North Dakota in 2011.
Employees
As of December 31, 2010, we had 87 full-time employees and 2 part-time employees. As of the
end of 2010, none of our employees were represented by labor unions and we believe relations with
them are good.
Website Access
We make available, free of charge through our website, www.bexp3d.com, our annual report on
Form 10-K, quarterly reports on Form 10-Q, current reports on form 8-K, and all amendments to those
reports as soon as reasonably practicable after such material is electronically filed with or
furnished to the Securities and Exchange Commission (SEC). Information on our website is not a part
of this report.
You should carefully consider the following risk factors, in addition to the other information
set forth in this report. Each of these risk factors could adversely affect our business, operating
results and financial condition.
Crude oil and natural gas prices are volatile and thus could be subject to further reduction, which
would adversely affect our results and the price of our common stock.
Our revenues, operating results and future rate of growth depend highly upon the prices we
receive for our crude oil and natural gas production. Historically, the markets for crude oil and
natural gas have been volatile and are likely to continue to be volatile in the future.
The NYMEX daily settlement price for the prompt month crude oil contract during 2010 ranged
from a high of $91.51 per barrel to a low of $68.01 per barrel. The NYMEX daily settlement price
for the prompt month crude oil contract in 2009 ranged from a high of $81.37 per barrel to a low of
$33.98 per barrel. In 2008, the same index ranged from a high of $145.29 per barrel to a low of
$33.87 per barrel.
The NYMEX daily settlement price for the prompt month natural gas contract during 2010 ranged
from a high of $7.51 per MMBtu to a low of $3.18 per MMBtu. The NYMEX daily settlement price for
the prompt month natural gas contract in 2009 ranged from a high of $6.07 per MMBtu to a low of
$2.51 per MMBtu. In 2008, the same index ranged from a high of $13.58 per MMBtu to a low of $5.29
per MMBtu.
9
The markets and prices for crude oil and natural gas depend on numerous factors beyond our
control. These factors include demand for crude oil and natural gas, which fluctuate with changes
in market and economic conditions and other factors, including:
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worldwide and domestic supplies of crude oil and natural gas; |
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actions taken by foreign crude oil and natural gas producing nations; |
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political conditions and events (including instability or armed conflict) in crude
oil-producing or natural gas producing regions; |
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the level of global and domestic crude oil and natural gas inventories; |
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the price and level of foreign imports including liquefied natural gas imports; |
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the level of consumer demand; |
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the price and availability of alternative fuels; |
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the availability of pipeline or other takeaway capacity; |
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domestic and foreign governmental regulations and taxes; and |
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the overall worldwide and domestic economic environment. |
Significant declines in crude oil and natural gas prices for an extended period may have the
following effects on our business:
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adversely affect our financial condition, liquidity, ability to finance planned capital
expenditures and results of operations; |
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reduce the amount of crude oil and natural gas that we can produce economically; |
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cause us to delay or postpone some of our capital projects; |
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reduce our revenues, operating income and cash flow; |
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reduce the carrying value of our crude oil and natural gas properties; and |
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limit our access to sources of capital, such as equity and long-term debt. |
The ongoing economic uncertainty could negatively impact the prices for crude oil and natural gas,
limit access to the credit and equity markets, increase the cost of capital, and may have other
negative consequences that we cannot predict.
The ongoing economic uncertainty in the U.S. could create financial challenges if conditions
do not improve. Our internally generated cash flow, our Senior Credit Facility and cash on hand
historically have not been sufficient to fund all of our expenditures, and we have relied on the
capital markets and sales of non-core assets to provide us with additional capital. Our ability to
access the capital markets may be restricted at a time when we would like, or need, to raise
capital. If our cash flow from operations is less than anticipated and our access to capital is
restricted, we may be required to reduce our operating and capital budget, which could have a
material adverse effect on our results and future operations. Ongoing uncertainty may also reduce
the values we are able to realize in asset sales or other transactions we may engage in to raise
capital, thus making these transactions more difficult to consummate and less economic.
Additionally, demand for crude oil and natural gas may deteriorate and result in lower prices for
crude oil and natural gas, which could have a negative impact on our revenues. Lower prices could
also adversely affect the collectability of our trade receivables and cause our commodity hedging
arrangements to be ineffective if our counterparties are unable to perform their obligations.
Our hedging activities may prevent us from benefiting from price increases and may expose us to
other risks.
In an attempt to reduce our sensitivity to energy price volatility and in particular to
downward price movements, we enter into hedging arrangements with respect to a portion of expected
production, such as the use of derivative contracts that generally result in a range of minimum and
maximum price limits or a fixed price over a specified time period. Our current strategy is to
hedge up to 100% of our proved developed producing reserves and up to 50% of the incremental oil
volumes associated with our Williston Basin drilling program over the next 24 months with costless
collars and puts.
10
Our hedging activities expose us to the risk of financial loss in certain circumstances. For
example, if we do not produce our crude oil and natural gas reserves at rates equivalent to our
derivative position, we would be required to satisfy our obligations under those derivative
contracts on potentially unfavorable terms without the ability to offset
that risk through sales of comparable quantities of our own production. Additionally, because
the terms of our derivative contracts are based on assumptions and estimates of numerous factors
such as cost of production and pipeline and other transportation and marketing costs to delivery
points, substantial differences between the prices we receive pursuant to our derivative contracts
and our actual results could harm our anticipated profit margins and our ability to manage the risk
associated with fluctuations in crude oil and natural gas prices. We also could be financially
harmed if the counterparties to our derivative contracts prove unable or unwilling to perform their
obligations under such contracts. Additionally, in the past, some of our derivative contracts
required us to deliver cash collateral or other assurances of performance to the counterparties if
our payment obligations exceeded certain levels. Future collateral requirements are uncertain but
will depend on arrangements with our counterparties, highly volatile crude oil and natural gas
prices and future rules and regulations to be promulgated by the Commodities Futures Trading
Commission (the CFTC) pursuant to the mandate of the United States Congress under the Dodd-Frank
Wall Street Reform and Consumer Protection Act. See Derivatives regulation included in current
financial reform legislation could impede our ability to manage business and financial risks by
restricting our use of derivative instruments as hedges against fluctuating commodity prices.
The results of our planned drilling in the Bakken and Three Forks objectives, an emerging play with
limited drilling and production history, are subject to more uncertainties than our drilling
program in the more established formations and may not meet our expectations for reserves or
production.
We have recently begun drilling wells in the Bakken and Three Forks objectives. Part of our
drilling strategy to maximize the net asset value and recoveries from the Bakken and Three Forks
objectives involves drilling horizontal wells using completion techniques that have proven
successful in other shale formations. Our experience with drilling horizontal wells in the Bakken
and Three Forks objectives to date, as well as the industrys drilling and production history in
the formation, is limited. The ultimate success of these drilling and completion strategies and
techniques in this formation will be better evaluated over time as more wells are drilled and
longer term production profiles are established. In addition, based on reported decline rates in
these formations in other areas and in other shale formations, we estimate the average monthly
rates of production should decline by approximately 70% during the first twelve months of
production. Actual decline rates may differ significantly. Accordingly, the results of our future
drilling in the emerging Bakken and Three Forks objectives are more uncertain than drilling results
in the other formations with established reserves and production histories.
Further, access to adequate gathering systems or pipeline takeaway capacity and the
availability of drilling rigs and other services may be more challenging in new or emerging plays.
If our drilling results are less than anticipated or we are unable to execute our drilling program
because of capital constraints, lease expirations, access to gathering systems and takeaway
capacity or otherwise, and/or crude oil and natural gas prices are depressed, the return on our
investment in these areas may not be as attractive as we anticipate and we could incur material
writedowns of unevaluated properties and the value of our undeveloped acreage could decline in the
future.
The lack of availability or high cost of drilling rigs, fracture stimulation crews, equipment,
supplies, insurance, personnel and oil field 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,
fracture stimulation crews, equipment, supplies, insurance 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. If levels of exploration and production increase in response to
strong crude oil and natural gas prices, the demand for oilfield services will likely rise, and the
costs of these services will likely increase, while at the same time the quality of these services
may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies,
insurance or qualified personnel were particularly severe in North Dakota, Montana, Texas, Southern
Louisiana, or Oklahoma, we could be materially and adversely affected because our operations and
properties are concentrated in those areas.
The proposed United States federal budgets for fiscal years 2011 and 2012 and proposed legislation
contain certain provisions that, if passed as originally submitted, will have an adverse effect on
our financial position, results of operations, and cash flows.
The Obama administrations budget proposals for fiscal years 2011 and 2012 each contain
numerous proposed tax changes, and from time to time, legislation has been introduced that would
enact many of these proposed changes. The proposed budget and legislation would repeal many tax
incentives and deductions that are currently used by U.S. oil and gas companies and impose new
taxes. Among others, the provisions include: elimination of the
ability to fully deduct intangible drilling costs in the year incurred; repeal of the
percentage depletion deduction for crude oil and gas properties; repeal of the domestic
manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical
amortization period for independent producers; and implementation of a fee on non-producing leases
located on federal lands. Should some or all of these provisions become law our taxes could
increase, potentially significantly, after net operating losses are exhausted, which would have a
negative impact on our net income and cash flows. This could also reduce our drilling activities.
We do not know the ultimate impact these proposed changes may have on our business.
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We depend on our key management personnel and technical experts and the loss any of these
individuals could adversely affect our business.
If we lose the services of our key management personnel, technical experts or are unable to
attract additional qualified personnel, our business, financial condition, results of operations,
development efforts and ability to grow could suffer. We have assembled a team of engineers,
geologists and geophysicists who have considerable experience in applying advanced drilling and
completion techniques to explore for and to develop crude oil and natural gas. We depend upon the
knowledge, skill and experience of these experts to assist us in improving the performance and
reducing the risks associated with our participation in crude oil and natural gas exploration and
development projects. In addition, the success of our business depends, to a significant extent,
upon the abilities and continued efforts of our management, particularly Ben M. Brigham, our Chief
Executive Officer, President and Chairman of the Board. We have an employment agreement with Mr.
Brigham, but do not have an employment agreement with any of our other employees.
Lower crude oil and natural gas prices may cause us to record ceiling limitation writedowns, which
would reduce our stockholders equity.
We use the full cost method of accounting for our crude oil and natural gas investments.
Accordingly, we capitalize the cost to acquire, explore for and develop crude oil and natural gas
properties. Under full cost accounting rules, the net capitalized cost of crude oil and natural gas
properties may not exceed a ceiling limit that is based upon the present value of estimated
future net revenues from proved reserves, discounted at 10%, plus the lower of the cost or fair
market value of unproved properties. If net capitalized costs of crude oil and natural gas
properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is
called a ceiling limitation writedown. The risk that we will experience a ceiling limitation
writedown increases when crude oil and natural gas prices are depressed or if we have substantial
downward revisions in estimated proved reserves. Based on crude oil and natural gas prices in
effect on March 31, 2009 ($3.63 per MMBtu for Henry Hub gas and $49.65 per barrel for West Texas
Intermediate crude oil, adjusted for differentials), the unamortized cost of our crude oil and
natural gas properties exceeded the ceiling limit. As such, we recorded a $114.8 million ($71.9
million after tax) impairment to our crude oil and gas properties at March 31, 2009. Based on crude
oil and natural gas prices in effect on December 31, 2008 ($5.71 per MMBtu for Henry Hub gas and
$44.60 per barrel for West Texas Intermediate crude oil, adjusted for differentials), the
unamortized cost of our crude oil and natural gas properties exceeded the ceiling limit. As such,
we recorded a $237.2 million ($148.6 million after tax) impairment to our crude oil and natural gas
properties at December 31, 2008. We may be required to recognize additional pre-tax non-cash
impairment charges in the future reporting periods if market prices for crude oil or natural gas
decline.
We may have difficulty financing our planned capital expenditures, which could adversely affect our
business.
We make and hope to continue to make substantial capital expenditures in our exploration and
development projects. Without additional capital resources, our drilling and other activities may
be limited and our business, financial condition and results of operations may suffer. We may not
be able to secure additional financing on reasonable terms or at all, and financing may not
continue to be available to us under our existing or new financing arrangements. If additional
capital resources are unavailable, we may curtail our drilling, development and other activities or
be forced to sell some of our assets on an untimely or unfavorable basis. Any such curtailment or
sale could have a material adverse effect on our business, financial condition and results of
operation.
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Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next
several years unless production is established on units containing the acreage or the leases are
extended.
As of December 31, 2010, we had mineral leases on approximately 364,309 net acres in the
Williston Basin which we believe are prospective for the Bakken and/or Three Forks. A significant
portion of the acreage is not currently held by production. Unless production in paying quantities
is established on units containing these leases during their primary terms or we obtain extensions
of the leases, these leases will expire. If our leases expire, we will lose our right to develop
the related properties.
Our drilling plans for these areas are subject to change based upon various factors, including
factors that are beyond our control, including drilling results, crude oil and natural gas prices,
the availability and cost of capital, drilling and production costs, availability of drilling
services and equipment, gathering system and pipeline transportation constraints, and regulatory
approvals.
Our exploration, development and drilling efforts and the operation of our wells may not be
profitable or achieve our targeted returns.
We require significant amounts of undeveloped leasehold acreage in order to further our
development efforts. Exploration, development, drilling and production activities are subject to
many risks, including the risk that commercially productive reservoirs will not be discovered. We
invest in property, including undeveloped leasehold acreage, which we believe will result in
projects that will add value over time. However, we cannot guarantee that all of our prospects will
result in viable projects or that we will not abandon our initial investments. Additionally, we
cannot guarantee that the leasehold acreage we acquire will be profitably developed, that new wells
drilled by us in provinces that we pursue will be productive or that we will recover all or any
portion of our investment in such leasehold acreage or wells. Drilling for crude oil and natural
gas may involve unprofitable efforts, not only from dry wells, but also from wells that are
productive but do not produce sufficient net reserves to return a profit after deducting operating
and other costs. Wells that are profitable may not achieve our targeted rate of return. Our ability
to achieve our target results is dependent upon the current and future market prices for crude oil
and natural gas, costs associated with producing crude oil and natural gas and our ability to add
reserves at an acceptable cost. Additionally, we rely to some extent on 3-D seismic data and other
advanced technologies in identifying leasehold acreage prospects and in conducting our exploration
activities. These technologies we use do not allow us to know conclusively prior to the acquisition
of leasehold acreage or the drilling of a well whether crude oil or natural gas is present or may
be produced economically.
In addition, we may not be successful in implementing our business strategy of controlling and
reducing our drilling and production costs in order to improve our overall return. The cost of
drilling, completing and operating a well is often uncertain and cost factors can adversely affect
the economics of a project. We cannot predict the cost of drilling, and we may be forced to limit,
delay or cancel drilling operations as a result of a variety of factors, including:
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unexpected drilling conditions; |
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pressure or irregularities in formations; |
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equipment failures or accidents; |
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adverse weather conditions; |
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compliance with governmental requirements; and |
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shortages or delays in the availability of drilling rigs, fracture stimulation crews or
other types of equipment necessary in the oil and gas industry. |
Exploratory drilling is a speculative activity that may not result in commercially productive
reserves and may require expenditures in excess of budgeted amounts.
Our future rate of growth somewhat depends on the success of our exploratory drilling program.
Exploratory drilling involves a higher degree of risk that we will not encounter commercially
productive crude oil or natural gas reservoirs than developmental drilling. We may not be
successful in our future drilling activities because, even with the use of advanced horizontal
drilling and completion techniques, 3-D seismic and other advanced technologies, exploratory
drilling is a speculative activity.
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Although our crude oil and natural gas reserve data is independently estimated, these estimates may
still prove to be inaccurate.
Our proved reserve estimates are prepared each year by Cawley, Gillespie & Associates, Inc.
(CGA), a registered independent petroleum consulting firm. In conducting its evaluation, the
engineers and geologists of CGA evaluate our properties and independently develop proved reserve
estimates. There are numerous uncertainties and risks that are inherent in estimating quantities of
crude oil and natural gas reserves and projecting future rates of production and timing of
development expenditures as many factors are beyond our control. There are many factors and
assumptions incorporated into our reserve estimates including:
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expected reservoir characteristics based on geological, geophysical and engineering
assessments; |
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future production rates based on historical performance and expected future operating and
investment activities; |
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future crude oil and gas prices and quality and location differentials; and |
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future development and operating costs. |
Although we believe the CGA reserve estimates are reasonable based on the information
available to them at the time they prepare their estimates, our actual results could vary
materially from these estimated quantities of proved crude oil and natural gas reserves (in the
aggregate and for a particular location), production, revenues, taxes and development and operating
expenditures. In addition, these estimates of proved reserves may be subject to downward or upward
revision based upon production history, results of future exploration and development, prevailing
crude oil and natural gas prices, operating and development costs and other factors.
Finally, recovery of proved undeveloped reserves generally requires significant capital
expenditures and successful drilling operations. At December 31, 2010, approximately 65% of our
estimated proved reserves were classified as undeveloped. At December 31, 2010, we estimated that
it would require additional capital expenditures of approximately $738.9 million to develop our
proved undeveloped reserves. Our reserve estimates assume that we can and will make these
expenditures and conduct these operations successfully, which may not occur.
We need to replace our reserves at a faster rate than companies whose reserves have longer
production periods. Our failure to replace our reserves would result in decreasing reserves and
production over time.
In general, production from crude oil and natural gas properties declines as reserves are
depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we
conduct successful exploration and development activities or acquire properties containing proved
reserves, or both, our proved reserves and production will decline as reserves are produced.
We may not be able to find, develop or acquire additional reserves to replace our current and
future production. Accordingly, our future crude oil and natural gas reserves and production and
therefore our future cash flow and income, are dependent upon our success in economically finding
or acquiring new reserves and efficiently developing our existing reserves.
Our reserves in the Gulf Coast have high initial production rates followed by steep declines in
production, resulting in a reserve life for wells in this area that is shorter than the industry
average. This production volatility has impacted and, in the future, may continue to impact our
quarterly and annual production levels.
We generally must locate and develop or acquire new crude oil and natural gas reserves to
replace those being depleted by production. Without successful drilling and exploration or
acquisition activities, our reserves and revenues will decline rapidly. We may not be successful in
extending the reserve life of our properties generally and our Gulf Coast properties in particular.
Our current strategy includes increasing our reserve base through drilling activities in our
Williston Basin province and in our other core areas, which have historically had longer-lived
reserves. Our existing and future exploration and development projects may not result in
significant additional reserves and we may not be able to drill productive wells at economically
viable costs.
Our future cash flows are subject to a number of variables, such as the level of production
from existing wells, prices of crude oil and natural gas and our success in finding and producing
new reserves. If our revenues were to decrease as a result of lower crude oil and natural gas
prices, decreased production or otherwise, and our access to capital were limited, we would have a
reduced ability to replace our reserves or to maintain production at current levels, potentially
resulting in a decrease in production and revenue over time.
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We may not drill all of our potential drilling locations and drilling locations that we decide to
drill may not yield crude oil or natural gas in commercially viable quantities or quantities
sufficient to meet our targeted rate of return.
Our drilling locations are in various stages of evaluation, ranging from locations that are
ready to be drilled to potential locations that will require substantial additional evaluation and
interpretation. Most of our potential drilling locations have not been attributed proved
undeveloped reserves. A decision to drill any specific well on our large inventory of potential
well locations may not be made for many years, if at all. If a decision is made to drill, there is
no way to conclusively predict in advance of drilling and testing whether any particular drilling
location will yield crude oil or natural gas in sufficient quantities to recover our drilling or
completion costs or to be economically viable. Our use of seismic data and other technologies and
the study of producing fields in the same area will not enable us to know conclusively prior to
drilling whether crude oil and natural gas will be present or, if present, whether crude oil and
natural gas will be present in commercial quantities. The analysis that we perform using data from
other wells, more fully explored prospects and/or producing fields 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 crude oil and natural gas and, therefore, we may not
achieve a targeted rate of return or have a positive return on investment.
The marketability of our crude oil and natural gas production depends on services and facilities
that we typically do not own or control. The failure or inaccessibility of any such services or
facilities could affect market based prices or result in a curtailment of production and revenues.
The marketability of our crude oil and natural gas production depends in part upon the
availability of, proximity to and capacity of crude oil and natural gas gathering and
transportation systems, crude oil and natural gas pipelines and processing facilities. We generally
deliver crude oil at our leases under short-term contracts. Counterparties to our short-term
contracts rely on access to regional transportation systems and pipelines. If transportation
systems or pipeline capacity is constrained, we would be required to find alternative
transportation modes, which would impact our market based price, or temporarily curtail production.
We generally deliver natural gas through gas gathering systems and gas pipelines that we do not own
under interruptible or short term transportation agreements. Under the interruptible transportation
agreements, the transportation of our natural gas may be interrupted due to capacity constraints on
the applicable system, for maintenance or repair of the system, or for other reasons as dictated by
the particular agreements. If any of the pipelines or other facilities become unavailable, we would
be required to find a suitable alternative to transport and process the natural gas, which could
increase our costs and reduce the revenues we might obtain from the sale of the natural gas. For
example, in 2008, Hurricanes Gustav and Ike disrupted our Gulf Coast operations forcing us to
temporarily curtail production and delayed bringing new wells on line. Hurricane Ike forced us to
curtail approximately 1.0 MMcfe per day of production during the third quarter 2008. Furthermore,
both Hurricanes Gustav and Ike delayed our completion operations on our Southern Louisiana wells
reducing third quarter 2008 production by an estimated 1.8 MMcfe per day.
We are subject to various operating and other casualty risks that could result in liability
exposure or the loss of production and revenues.
Our operations are subject to hazards and risks inherent in drilling for and producing and
transporting crude oil and natural gas, such as:
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formations with abnormal pressures; |
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blowouts, cratering and explosions; and |
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pipeline ruptures and spills. |
Any of these hazards and risks can result in the loss of hydrocarbons, environmental
pollution, personal injury claims and other damage to our properties and the property of others.
15
We may not have enough insurance to cover all of the risks we face, which could result in
significant financial exposure.
We maintain insurance coverage against some, but not all, potential losses in order to protect
against the risks we face. We may elect not to carry insurance if our management believes that the
cost of insurance is excessive relative to the risks presented. If an event occurs that is not
covered, or not fully covered, by insurance, it could harm our financial condition, results of
operations and cash flows. In addition, we cannot fully insure against pollution and environmental
risks.
We cannot control activities on properties we do not operate. Failure to fund capital expenditure
requirements may result in reduction or forfeiture of our interests in some of our non-operated
projects.
We do not operate some of the properties in which we have an interest and we have limited
ability to exercise influence over operations for these properties or their associated costs. As of
December 31, 2010, approximately 19% of our crude oil and natural gas proved reserves were operated
by other companies. Our dependence on other operators and other working interest owners for these
projects and our limited ability to influence operations and associated costs could materially
adversely affect the realization of our targeted return on capital in drilling or acquisition
activities and our targeted production growth rate. The success and timing of drilling, development
and exploitation activities on properties operated by others depend on a number of factors that are
beyond our control, including the operators expertise and financial resources, approval of other
participants for drilling wells and utilization of technology.
When we are not the majority owner or operator of a particular crude oil or natural gas
project, we may have no control over the timing or amount of capital expenditures associated with
such project. If we are not willing or able to fund our capital expenditures relating to such
projects when required by the majority owner or operator, our interests in these projects may be
reduced or forfeited.
Our future operating results may fluctuate and significant declines in them would limit our ability
to invest in projects.
Our future operating results may fluctuate significantly depending upon a number of factors,
including:
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prices of crude oil and natural gas; |
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rates of drilling success; |
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rates of production from completed wells; and |
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the timing and amount of capital expenditures. |
This variability could cause our business, financial condition and results of operations to
suffer. In addition, any failure or delay in the realization of expected cash flows from operating
activities could limit our ability to invest and participate in economically attractive projects.
We face significant competition and many of our competitors have resources in excess of our
available resources.
We operate in the highly competitive areas of crude oil and natural gas exploration,
exploitation, acquisition and production. We face intense competition from a large number of
independent, technology-driven companies as well as both major and other independent oil and
natural gas companies in a number of areas such as:
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seeking to acquire desirable producing properties or new leases for future exploration; |
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marketing our crude oil and natural gas production; and |
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seeking to acquire the equipment and expertise necessary to operate and develop those
properties. |
Many of our competitors have financial and other resources substantially in excess of those
available to us. This highly competitive environment could harm our business.
16
We are subject to various governmental regulations and environmental risks that may cause us to
incur substantial costs.
From time to time, in varying degrees, political developments and federal and state laws and
regulations affect our operations. In particular, price controls, taxes and other laws relating to
the oil and natural gas industry, changes in these laws and changes in administrative regulations
have affected and in the future could affect crude oil and natural gas production, operations and
economics. We cannot predict how agencies or courts will interpret existing laws and regulations or
the effect of these adoptions and interpretations may have on our business or financial condition.
Our business is subject to laws and regulations promulgated by federal, state and local
authorities, including but not limited to the United States Congress, FERC, the EPA, the BLM, the
TRRC, the TCEQ, the OCC, the LDNR, the NDIC and the MBOGC relating to the exploration for, and the
development, production and marketing of, crude oil and natural gas, as well as safety matters.
Legal requirements are frequently changed and subject to interpretation and we are unable to
predict the ultimate cost of compliance with these requirements or their effect on our operations.
We may be required to make significant expenditures to comply with governmental laws and
regulations. The discharge of crude oil, natural gas or other pollutants into the air, soil or
water may give rise to significant liabilities on our part to the government and third parties and
may require us to incur substantial costs of remediation.
Our operations are subject to complex federal, state and local environmental laws and
regulations, including the CERCLA, the Resource Conservation and Recovery Act, the OPA, and the
Clean Water Act. Environmental laws and regulations change frequently, and the implementation of
new, or the modification of existing, laws or regulations could harm us. For example, in the 111th
Congress, companion bills were introduced in the United States Senate and House of Representatives.
These bills would have repealed the exemption for hydraulic fracturing from the federal Safe
Drinking Water Act, which would have had the effect of allowing the EPA to promulgate regulations
requiring permits and imposing new restrictions on hydraulic fracturing under the federal Safe
Drinking Water Act. This could, in turn, require state regulatory agencies in states with programs
delegated under the Safe Drinking Water Act to impose additional requirements on hydraulic
fracturing operations. In addition, the bills would have required persons using hydraulic
fracturing, such as us, to disclose the chemical constituents, but not the proprietary formulas, of
their fracturing fluids to a regulatory agency, which would make the information public via the
internet, which could make it easier for third parties opposing the hydraulic fracturing process to
initiate legal proceedings based on allegations that specific chemicals used in the fracturing
process could adversely affect groundwater. If legislation similar to that introduced in the 111th
Congress becomes law, it could establish an additional level of regulation at the federal level
that could lead to operational delays or increased operating costs and could result in additional
regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase
our costs of compliance and doing business. Compliance or the consequences of any failure to comply
by us could have a material adverse effect on our financial condition and results of operations. At
this time, it is not possible to estimate the potential impact on our business that may arise if
the federal or state legislation is enacted into law. In addition, in March 2010, the EPA announced
its intention to conduct a comprehensive research study on the potential adverse impacts that
hydraulic fracturing may have on water quality and public health. Preliminary results of the study
are expected in 2012. Thus, even if the pending legislation is not adopted, the EPA study, depending
on its results, could spur further initiatives to regulate hydraulic fracturing under the Safe
Drinking Water Act.
Derivatives regulation included in current financial reform legislation could impede our ability to
manage business and financial risks by restricting our use of derivative instruments as hedges
against fluctuating commodity prices.
Last year, the United States Congress recently adopted the Dodd-Frank Wall Street Reform and
Consumer Protection Act, which contains comprehensive financial reform legislation that establishes
federal oversight and regulation of the over-the-counter derivatives market and entities, such as
the Company, that participate in that market. The new legislation was signed into law by the
President on July 21, 2010 and requires the CFTC and the SEC to promulgate rules and regulations
implementing the new legislation within 360 days from the date of enactment. The CFTC has also
proposed regulations to set position limits for certain futures and option contracts in the major
energy markets, although it is not possible at this time to predict whether or when the CFTC will
adopt those rules or include comparable provisions in its rulemaking under the new legislation. The
financial reform legislation contains significant derivatives regulation, including provisions
requiring certain transactions to be cleared on exchanges and containing a requirement to post cash
collateral (commonly referred to as margin) for such transactions as well as certain clearing and
trade-execution requirements in connection with our derivative
activities. The Act provides for a potential exception from these clearing and cash collateral
requirements for commercial end-users and it includes a number of defined terms that will be used
in determining how this exception applies to particular derivative transactions and to the parties
to those transactions. However, we do not know the definitions that the CFTC will actually
promulgate nor how these definitions will apply to us. The financial reform legislation may also
require the counterparties to our derivative instruments to spin off some of their derivatives
activities to a separate entity, which may not be as creditworthy as the current counterparty.
17
Depending on the rules and definitions adopted by the CFTC, we could be required to post cash
collateral with our dealer counterparties for our commodities hedging transactions. The new
legislation and any new regulations could significantly increase the cost of derivative contracts
(including through requirements to post cash collateral which could adversely affect our available
liquidity, thereby reducing our ability to use cash for investment or other corporate purposes, or
could require us to increase our level of debt), materially alter the terms of derivative
contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our
ability to monetize or restructure our existing derivative contracts, and increase our exposure to
less creditworthy counterparties. If we reduce our use of derivatives as a result of the
legislation and regulations, our results of operations may become more volatile and our cash flows
may be less predictable, which could adversely affect our ability to plan for and fund capital
expenditures. Finally, the legislation was intended, in part, to reduce the volatility of crude oil
and natural gas prices, which some legislators attributed to speculative trading in derivatives and
commodity instruments related to crude oil and natural gas. Our revenues could therefore be
adversely affected if a consequence of the legislation and regulations is to lower commodity
prices. In addition, a requirement for our counterparties to post cash collateral would likely
result in additional costs being passed on to us, thereby decreasing the effectiveness of our
hedges and our profitability. Any of these consequences could have a material, adverse effect on
us, our financial condition, and our results of operations.
The adoption of climate change legislation by Congress could result in increased operating costs
and reduced demand for the crude oil and natural gas we produce.
In the 111th Congress, two climate change bills were introduced that would have established a
cap and trade system for restricting greenhouse gas emissions. Under such 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 current or a future Congress could enact similar
legislation. In addition to the possible climate legislation, the 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. On November 8, 2010, the EPA
finalized a rule that sets forth reporting requirements for the petroleum and natural gas industry
and requires persons that hold state drilling permits and that emit 25,000 metric tons or more of
carbon dioxide equivalent per year to annually report carbon dioxide, methane and nitrous oxide
emissions from certain sources. 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 EPA has proposed regulations
that would require permits for and reductions in greenhouse gas emissions for certain facilities,
and may issue final rules in 2011. Any laws or regulations that may be adopted to restrict or
reduce emissions of GHGs could require us to incur increased operating costs, and could have an
adverse effect on demand for the crude oil and natural gas we produce, depending on the
applicability to company operations and the refining, processing, and use of crude oil and gas.
Our level of indebtedness may adversely affect our cash available for operations, which would limit
our growth, our ability to make interest and principal payments on our indebtedness as they become
due and our flexibility to respond to market changes.
As of February 25, 2011, we had $300 million in outstanding indebtedness, as well as $325
million of borrowing capacity under our Senior Credit Facility. Our level of indebtedness will have
several important effects on our operations, including:
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we will dedicate a portion of our cash flow from operations to the payment of interest on
our indebtedness and to the payment of our other current obligations and will not have these
cash flows available for other purposes; |
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our debt agreements limit our ability to borrow additional funds or dispose of assets and
may affect our flexibility in planning for, and reacting to, changes in business conditions; |
18
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our ability to obtain additional financing in the future for working capital, capital
expenditures, acquisitions, general corporate purposes or other purposes may be impaired; |
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we may be more vulnerable to economic downturns and our ability to withstand sustained
declines in oil and natural gas prices may be impaired; |
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since outstanding balances under our Senior Credit Facility are subject to variable
interest rates, we are vulnerable to increases in interest rates; |
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our flexibility in planning for or reacting to changes in market conditions may be
limited; and |
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it may place us at a competitive disadvantage compared to our competitors that have less
debt. |
Our ability to meet our debt obligations and reduce our level of indebtedness depends on
future performance. General economic conditions, oil and natural gas prices and financial, business
and other factors will affect our operations and our future performance. Many of these factors are
beyond our control and we may not be able to generate sufficient cash flow to pay the interest on
our debt. In addition, borrowings and equity financing may not be available to pay or refinance
such debt.
The indenture governing the Senior Notes and the documents governing our Senior Credit Facility
impose significant operating and financial restrictions, which may prevent us from capitalizing on
business opportunities and taking some actions.
The indenture governing the notes and the documents governing our Senior Credit Facility
contain customary restrictions on our activities, including covenants that restrict our and our
subsidiaries ability to:
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pay dividends on, redeem or repurchase stock; |
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make specified types of investments; |
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apply net proceeds from certain asset sales; |
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engage in transactions with our affiliates; |
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engage in sale and leaseback transactions; |
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restrict dividends or other payments from subsidiaries; |
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sell equity interests of subsidiaries; and |
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sell, assign, transfer, lease, convey or dispose of assets. |
The indenture governing our Senior Notes contains certain incurrence-based covenants that will
limit our ability to incur debt and engage in other transactions. One of these covenants
incorporates the net present value of our proved reserves calculated based on SEC rules. Our
ability to increase our borrowings in 2011 will depend, in part, on prices for oil and natural gas
utilized in our year-end 2010 reserve report. Our Senior Credit Facility also requires us to meet a
minimum current ratio and a net leverage ratio. We may not be able to maintain or comply with these
ratios, and if we fail to be in compliance with these tests, we will not be able to borrow funds
under our Senior Credit Facility, which would make it difficult for us to operate our business.
The restrictions in the indenture governing the Senior Notes and the documents governing our
Senior Credit Facility may prevent us from taking actions that we believe would be in the best
interest of our business, and may make it difficult for us to successfully execute our business
strategy or effectively compete with companies that are not similarly restricted. We may also incur
future debt obligations that might subject us to additional restrictive covenants that could affect
our financial and operational flexibility. We cannot assure you that we will be granted waivers or
amendments to these agreements if for any reason we are unable to comply with these agreements, or
that we will be able to refinance our debt on terms acceptable to us, or at all.
The breach of any of these covenants and restrictions could result in a default under the
indenture governing the Senior Notes or under the documents governing our Senior Credit Facility.
An event of default under our debt agreements would permit some of our lenders to declare all
amounts borrowed from them to be due and payable. If we are unable to repay such indebtedness,
lenders having secured obligations, such as the lenders under our Senior
Credit Facility, could proceed against the collateral securing the debt. Because the indenture
governing the notes and the documents governing our Senior Credit Facility have customary
cross-default provisions, if the indebtedness under the notes or under our Senior Credit Facility
or any of our other facilities is accelerated, we may be unable to repay or finance the amounts
due.
19
Availability under our Senior Credit Facility is based on a borrowing base which is subject to
redetermination by our lenders. If our borrowing base is reduced, we may be required to repay
amounts outstanding under our Senior Credit Facility.
Under the terms of our Senior Credit Facility, our borrowing base is subject to semi-annual
redetermination by our lenders based on their valuation of our proved reserves and their internal
criteria. In addition to such semi-annual determinations, our lenders may request one additional
borrowing base redetermination during any 12-month period. Our borrowing base is also subject to
reduction if we monetize certain of our hedging transactions. In the event the amount outstanding
under our Senior Credit Facility at any time exceeds the borrowing base at such time, we may be
required to repay a portion of our outstanding borrowings over a period no longer than six months.
If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or
amendment from our lenders, refinance our Senior Credit Facility, sell assets or sell additional
shares of common stock. We may not be able obtain such financing or complete such transactions on
terms acceptable to us, or at all. Failure to make the required repayment could result in a default
under our Senior Credit Facility, which could adversely affect our business, financial condition
and results or operations. Our borrowing base is currently set at $325 million until the next
borrowing base redetermination provided for in the Senior Credit Facility, which is scheduled for
November 2011. We have no borrowings drawn on our Senior Credit Facility.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt
service obligations to increase significantly.
Borrowings under our Senior Credit Facility bear interest at variable rates and expose us to
interest rate risk. If interest rates increase, our debt service obligations on the variable rate
indebtedness would increase although the amount borrowed remained the same, and our net income and
cash available for servicing our indebtedness would decrease.
We may incur additional indebtedness. This could further exacerbate the risks associated with our
substantial leverage.
We may incur substantial additional indebtedness in the future. The indenture that will govern
the notes and documents governing our Senior Credit Facility contain restrictions on our ability to
incur indebtedness. These restrictions, however, are subject to a number of qualifications and
exceptions, and under certain circumstances we could incur substantial additional indebtedness in
compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring
obligations that do not constitute Indebtedness or Debt under the indenture and the Senior
Credit Facility, respectively. If we incur indebtedness above our current debt levels, the related
risks that we now face could intensify and we may not be able to meet all our debt obligations.
Failure to meet these obligations could result in a default under our debt documents, which could
adversely affect our business, financial condition and results of operations.
To service our indebtedness we will require a significant amount of cash. Our ability to generate
cash depends on many factors beyond our control. Failure to generate sufficient cash to service our
indebtedness could adversely affect our business, financial condition and results of operations.
Our ability to meet our debt obligations and other expenses will depend on our future
performance, which will be subject to general economic, financial, competitive, legislative,
regulatory and other factors that are beyond our control. We cannot assure you that our business
will generate sufficient cash flow from operations or that future borrowings will be available to
us under our Senior Credit Facility or otherwise in an amount sufficient to enable us to pay our
indebtedness or to fund our other liquidity needs.
20
If we are unable to meet our debt service obligations, we may be required to seek a waiver or
amendment from our debt holders, refinance such debt obligations or sell assets or additional
shares of common stock. We may not be
able obtain such financing or complete such transactions on terms acceptable to us, or at all.
Failure to meet our debt obligations could result in a default under the agreements governing our
indebtedness. An event of default under our debt agreements would permit some of our lenders to
declare all amounts borrowed from them to be due and payable. If we are unable to repay such
indebtedness, lenders having secured obligations, such as the lenders under our Senior Credit
Facility, could proceed against the collateral securing the debt. Because the indenture governing
the notes and the documents governing our Senior Credit Facility have customary cross-default
provisions, if the indebtedness under the notes or under our Senior Credit Facility or any of our
other facilities is accelerated, we may be unable to repay or finance the amounts due.
The market price of our stock is volatile.
The trading price of our common stock and the price at which we may sell securities in the
future are subject to large fluctuations in response to any of the following:
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limited trading volume in our stock; |
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changes in government regulations; |
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quarterly variations in operating results; |
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our involvement in litigation; |
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general market conditions; |
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the prices of crude oil and natural gas; |
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announcements by us and our competitors; |
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our ability to raise additional funds; and |
Our stock price may decline when our financial results decline or when events occur that are
adverse to us or our industry.
You can expect the market price of our common stock to decline when our financial results
decline or otherwise fail to meet the expectations of the financial community or the investing
public or at any other time when events actually or potentially adverse to us or the oil and
natural gas industry occur. Our common stock price may decline to a price below the price you paid
to purchase your shares of common stock.
We are prohibited from paying dividends on our common stock.
We will retain all future earnings and other cash resources for the future operation and
development of our business. The documents governing our Senior Credit Facility and the indenture
governing our Senior Notes prohibit the payment of dividends. Accordingly, we do not intend to
declare or pay any cash dividends on our common stock in the foreseeable future.
Certain anti-takeover provisions may adversely affect your rights as a stockholder.
Our certificate of incorporation authorizes our Board of Directors to issue up to 10 million
shares of preferred stock without stockholder approval and to set the rights, preferences and other
designations, including voting rights, of those shares as the Board of Directors may determine. In
addition, the documents governing our Senior Credit Facility and our indenture governing our Senior
Notes contain terms restricting our ability to enter into change of control transactions, including
requirements to redeem or repay upon a change in control, the amounts borrowed under our Senior
Credit Facility and our Senior Notes. These provisions, alone or in combination with the other
matters described in the preceding paragraph, may discourage transactions involving actual or
potential changes in our control, including transactions that otherwise could involve payment of a
premium over prevailing market prices to holders of our common stock. We are also subject to
provisions of the Delaware General Corporation Law that may make some business combinations more
difficult.
21
Forward-Looking Statements
This report and the documents incorporated by reference in this annual report on Form 10-K
contain forward-looking statements within the meaning of the federal securities laws.
These forward-looking statements include, among others, the following:
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our ability to successfully and economically explore for and develop crude oil and
natural gas resources; |
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anticipated trends in our business; |
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our future results of operations; |
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our liquidity and ability to finance our exploration and development activities; |
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market conditions in the oil and gas industry; |
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our ability to make and integrate acquisitions; and |
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the impact of governmental regulation. |
Forward-looking statements are typically identified by use of terms such as may, will,
expect, anticipate, estimate and similar words, although some forward-looking statements may
be expressed differently.
You should be aware that our actual results could differ materially from those contained in
the forward-looking statements. You should consider carefully the statements in this Item 1A. Risk
Factors and other sections of this report, which describe factors that could cause our actual
results to differ from those set forth in the forward-looking statements.
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Item 1B. |
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Unresolved Staff Comments |
None.
22
Historically, our exploration and development activities have been focused in our Onshore Gulf
Coast, the Anadarko Basin and West Texas provinces. However, in late 2007, the majority of our
capital expenditures shifted from our historically active areas to the Williston Basin, where we
are primarily targeting the Bakken and Three Forks producing horizons. As of December 31, 2010, we
had approximately 600,601 gross and 364,309 net leasehold acres in the Williston Basin. In 2010, we
drilled and completed or were in the process of completing 151 gross (38.9 net) wells on our
Williston Basin acreage investing a total of $404.8 million on drilling, land and support
infrastructure, before the impact of asset sale proceeds. At year-end 2010, we were also drilling 21 gross (2.7 net) wells. Since entering
the Williston Basin in late 2005, we have invested in excess of $625 million on drilling, land,
seismic and support infrastructure.
In 2010, we spent a total of approximately $426.8 million
on drilling, land and
support infrastructure in our operating areas. During 2011, we plan to spend approximately $582.1
million on drilling 68.1 net wells as well as to complete wells that were in progress at December
31, 2010. We currently expect to spend approximately $27.4 million on land. Finally, we expect to
spend $83.2 million on support infrastructure to continue to expand gathering lines and add water
disposal wells. See Item 7. Managements Discussion and Analysis of Financial Condition and
Results of Operations Capital Commitments Capital Expenditures. The following is a summary
of our properties by major province as of December 31, 2010, unless otherwise noted.
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Williston |
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Onshore |
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Anadarko |
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West Texas |
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Basin |
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Gulf Coast |
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Basin |
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and Other |
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Total |
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Capital expenditures for
drilling, land and
support infrastructure in 2010
(in millions) (a) |
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$ |
404.8 |
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$ |
16.4 |
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$ |
0.7 |
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$ |
4.9 |
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$ |
426.8 |
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Proved Reserves at December
31, 2010 |
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Pre-tax PV10% (in millions) (b) |
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$ |
939.4 |
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$ |
127.7 |
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$ |
22.1 |
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$ |
19.5 |
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$ |
1,108.7 |
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Crude oil (MMBbls) |
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49.5 |
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1.6 |
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0.2 |
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0.9 |
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52.2 |
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Natural gas (Bcf) |
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36.3 |
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36.2 |
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14.5 |
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0.8 |
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|
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87.8 |
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Oil equivalents (MMBoe) (c) |
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55.5 |
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7.6 |
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2.6 |
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|
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1.1 |
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|
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66.8 |
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% Oil |
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|
89 |
% |
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21 |
% |
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|
7 |
% |
|
|
87 |
% |
|
|
78 |
% |
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|
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|
|
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|
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Average daily production
volumes (MBoe) (d) |
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6,146 |
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|
|
1,394 |
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|
|
558 |
|
|
|
169 |
|
|
|
8,267 |
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Average daily sales volumes
(MBoe)(d) |
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|
6,064 |
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|
|
1,394 |
|
|
|
558 |
|
|
|
169 |
|
|
|
8,185 |
|
|
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|
|
|
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|
|
|
|
|
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|
|
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Productive wells at December
31, 2010 |
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Gross |
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|
237 |
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|
|
85 |
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|
|
89 |
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|
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31 |
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|
|
442 |
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Net |
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|
61.0 |
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|
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44.5 |
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|
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23.6 |
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|
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7.6 |
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|
|
136.7 |
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(a) |
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Onshore Gulf Coast, Anadarko Basin and West Texas & Other capital expenditures are before the
impact of proceeds from the sale of assets. |
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(b) |
|
The standardized measure for our proved reserves at December 31, 2010, was $866.1 million.
See - Reconciliation of Standardized Measure to Pre-tax PV10% for a definition of pre-tax
PV10% and a reconciliation of our standardized measure to our pre-tax PV10% value. The prices
used to calculate this measure were $79.43 per barrel of oil and $4.376 per MMbtu of natural
gas. These prices represent the average prices per barrel of oil and per MMbtu of natural gas
at the beginning of each month in the 12-month period prior to the end of the reporting
period. These prices were adjusted to reflect applicable transportation and quality
differentials on a well-by-well basis to arrive at realized sales prices used to estimate our
reserves at this date. |
|
(c) |
|
Boe is defined as one barrel of oil equivalent determined using the ratio of six Mcf of
natural gas to one barrel of crude oil, condensate or natural gas liquids. |
|
(d) |
|
Average daily production volumes calculated based on 360 day year. Average daily production
volumes include approximately 29,654 barrels of oil produced during 2010 and recorded as
inventory at year-end 2010. Total oil inventory at year-end 2010 and 2009 was 46,129 and
16,475 barrels of crude oil, respectively. Total crude oil
inventory at year-end 2008 was not material. Adjusting production volumes for amounts included
in inventory would result in average daily sales volumes in 2010 and 2009 of 8,185 and 4,988
barrels of oil per day. |
23
Williston Basin Province
In late 2005, we began accumulating acreage in the Williston Basin located in North Dakota and
Montana. During 2010, we invested approximately $404.8 million in drilling, land and
support infrastructure. During 2010, we drilled and completed or were in the process of completing
151 gross wells (38.9 net) in the Williston Basin. At year-end 2010, there were 21 gross wells
(2.7 net) drilling.
Overview of Williston Basin
The Williston Basin is spread across North Dakota, Montana and parts of southern Canada with
the United States portion of the basin encompassing approximately 125,000 square miles. The basin
produces oil and gas from numerous horizons including, but not limited to, the Bakken and Three
Forks, which are currently our primary horizontal objectives.
The Bakken is an unconventional oil shale play at depths of approximately 10,000 to 10,500
feet that is primarily exploited via advanced drilling and completion techniques. The Bakken
interval is comprised, from top to bottom, of the Upper Bakken Shale, Middle Bakken and Lower
Bakken Shale. The Upper and Lower Bakken Shales are lithologically similar world class source
rocks with total organic content of approximately 11%. Both the Upper and Lower Bakken Shales
serve as the source rock for the Middle Bakken, which is a dolomite and is the zone targeted for
our horizontal well bores. The dolomitic nature of the Middle Bakken allows us to propagate
fractures during our multi-stage fracture stimulations and we retain long-term conductivity to the
well bore via the use of ceramic proppants. During 2010, industry activity greatly increased west
of the Nesson Anticline in Williams and McKenzie Counties, North Dakota. Industry activity is also
increasing westward into Eastern Montana in both Richland and Roosevelt Counties.
The upper Three Forks is an unconventional carbonate play that lies just below the Bakken and
is charged by the Lower Bakken Shale. Similar to the Middle Bakken, the upper Three Forks is
primarily exploited using advanced drilling and completion techniques, which include multi-stage
fracture stimulations. Drilling in the upper Three Forks began in mid-2008 and a number of
operators, including us, are targeting this formation as a parallel objective to the Bakken
formation. Drilling in this formation is early, but initial results appear to indicate that the
upper Three Forks is a separate reservoir from the Bakken, which increases our exposure to crude
oil reserves in the basin.
Overview of Williston Basin Acreage Position
Our acreage position in the Williston Basin is comprised of approximately 364,309 net acres.
Approximately 95,011 net acres is east of the Nesson Anticline in Mountrail County, North Dakota
and adjoining counties to the north, south and east. Acreage east of the Nesson Anticline includes
approximately 5,319 net acres in our Parshall / Austin / Sanish project area in Mountrail County
where drilling activities are typically operated by others and we therefore participate in wells in
a non-operated role. Acreage east of the Nesson Anticline also incorporates approximately 34,960
net acres in our Ross Project area in Mountrail County where we both operate and participate in
non-operated Bakken and Three Forks wells.
Approximately 155,065 net acres are west of the Nesson Anticline in Williams and McKenzie
Counties, North Dakota in our Rough Rider project area. Acreage in our Rough Rider project area is
subject to the Drilling Participation Agreement outlined below. Typically, because of our higher
working interests in spacing units, we operate wells in our Rough Rider area but to a lesser degree
will also participate in wells in a non-operated role.
Our remaining 114,233 net acres are located in eastern Montana in Roosevelt, Richland and
Sheridan Counties in our Eastern Montana project area. Industry activity in Montana has been
increasing with a number of operators drilling and permitting wells in and around our acreage.
24
Overview of Rough Rider Drilling Participation Agreement
In late August 2009, we entered into a drilling participation agreement in our Rough Rider
project area in order to accelerate operations and address near term state lease expirations. The
initial 15 wells under the agreement have been drilled or were in the process of being drilled at
year-end. In each of the initial six wells, we have retained 35% of our original working interest
and will back in for 35% of our counterpartys interest in the combined six well group after
combined payout (defined as the point in time when the cumulative net receipts from the initial
wells equals or exceeds all expenditures for such wells). Our counterparty exercised its option to
participate in the additional nine wells and we elected to retain our maximum interest of 50% of
our original working interest in the additional nine wells. Further, we will have the option to
keep up to 64% of our original working interest in all subsequent in fill development wells in all
15 drilling units.
2010 Williston Basin Drilling and Completion Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FRAC |
|
|
IP |
|
|
30 DAY |
|
WELL NAME |
|
County |
|
|
OBJECTIVE |
|
|
~WI |
|
|
STAGES |
|
|
(Boe/d) |
|
|
Average (Boe/d)** |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Arvid Anderson 14-11 #1H |
|
Mountrail |
|
Bakken |
|
|
68 |
% |
|
|
38 |
|
|
|
3,191 |
|
|
|
1,330 |
|
Roger Sorenson 8-5 #1H |
|
Mountrail |
|
Bakken |
|
|
54 |
% |
|
|
38 |
|
|
|
2,658 |
|
|
|
1,120 |
|
Heen 26-35 #1H |
|
Williams |
|
Bakken |
|
|
76 |
% |
|
|
38 |
|
|
|
3,791 |
|
|
|
1,379 |
|
Brakken 30-31 #1H |
|
Williams |
|
Bakken |
|
|
56 |
% |
|
|
30 |
|
|
|
3,573 |
|
|
|
1,277 |
|
Lippert 1-12 #1H |
|
Williams |
|
Bakken |
|
|
66 |
% |
|
|
31 |
|
|
|
2,214 |
|
|
|
942 |
|
Brad Olson 9-16 #2H |
|
Williams |
|
Bakken |
|
|
56 |
%* |
|
|
32 |
|
|
|
2,717 |
|
|
|
773 |
|
Smith Farms 23-14 #1H |
|
Williams |
|
Bakken |
|
|
82 |
% |
|
|
32 |
|
|
|
2,417 |
|
|
|
1,041 |
|
Abelmann 23-14 #1H |
|
McKenzie |
|
Bakken |
|
|
53 |
% |
|
|
33 |
|
|
|
4,169 |
|
|
|
1,407 |
|
Clifford Bakke 26-35 #1H |
|
Mountrail |
|
Bakken |
|
|
43 |
% |
|
|
38 |
|
|
|
5,061 |
|
|
|
2,328 |
|
Boots 13-24 #1H |
|
Williams |
|
Bakken |
|
|
74 |
% |
|
|
31 |
|
|
|
1,946 |
|
|
|
662 |
|
Larsen 3-10 #1H |
|
Williams |
|
Bakken |
|
|
72 |
% |
|
|
31 |
|
|
|
3,090 |
|
|
|
1,034 |
|
Domaskin 30-31 #1H |
|
Mountrail |
|
Bakken |
|
|
65 |
% |
|
|
38 |
|
|
|
4,675 |
|
|
|
1,882 |
|
State 36-1 #2H |
|
Williams |
|
Three Forks |
|
|
30 |
%* |
|
|
31 |
|
|
|
2,356 |
|
|
|
874 |
|
Sukut 28-33 #1H |
|
Williams |
|
Bakken |
|
|
42 |
%* |
|
|
32 |
|
|
|
1,959 |
|
|
|
801 |
|
Abe Owan 21-16 #1H |
|
Williams |
|
Bakken |
|
|
57 |
% |
|
|
37 |
|
|
|
2,213 |
|
|
|
900 |
|
Weisz 11-14 #1H |
|
Williams |
|
Bakken |
|
|
52 |
% |
|
|
37 |
|
|
|
2,278 |
|
|
|
1,014 |
|
Wright 4-33 #1H |
|
Mountrail |
|
Bakken |
|
|
88 |
% |
|
|
38 |
|
|
|
3,660 |
|
|
|
1,322 |
|
Michael Owan 26-35 #1H |
|
Williams |
|
Bakken |
|
|
87 |
% |
|
|
33 |
|
|
|
2,931 |
|
|
|
889 |
|
Sedlacek Trust 33-4 #1H |
|
McKenzie |
|
Bakken |
|
|
48 |
%* |
|
|
30 |
|
|
|
2,695 |
|
|
|
826 |
|
Rogney 17-8 #1H |
|
Roosevelt |
|
Bakken |
|
|
100 |
% |
|
|
30 |
|
|
|
909 |
|
|
|
355 |
|
Ross Alger 6-7 #1H |
|
Mountrail |
|
Bakken |
|
|
47 |
% |
|
|
32 |
|
|
|
3,070 |
|
|
|
1,465 |
|
Owan 29-32 #1H |
|
Williams |
|
Bakken |
|
|
78 |
% |
|
|
31 |
|
|
|
2,302 |
|
|
|
868 |
|
Abe 30-31 #1H |
|
Williams |
|
Bakken |
|
|
97 |
% |
|
|
31 |
|
|
|
1,847 |
|
|
|
731 |
|
Jack Cvancara 19-18 #1H |
|
Mountrail |
|
Bakken |
|
|
83 |
% |
|
|
36 |
|
|
|
5,035 |
|
|
|
1,800 |
|
Tjelde 29-32 #1H |
|
McKenzie |
|
Bakken |
|
|
77 |
% |
|
|
30 |
|
|
|
3,171 |
|
|
|
931 |
|
Abelmann State 21-16 #1H |
|
McKenzie |
|
Bakken |
|
|
64 |
% |
|
|
31 |
|
|
|
3,301 |
|
|
|
1,044 |
|
Mortenson 5-32 #1H |
|
Williams |
|
Bakken |
|
|
77 |
% |
|
|
23 |
|
|
|
2,314 |
|
|
|
584 |
|
Arnson 13-24 #1H |
|
Williams |
|
Bakken |
|
|
93 |
% |
|
|
30 |
|
|
|
1,339 |
|
|
|
480 |
|
Sorenson 29-32 #1H |
|
Mountrail |
|
Bakken |
|
|
95 |
% |
|
|
27 |
|
|
|
5,133 |
|
|
|
1,909 |
|
Jack Erickson 6-31 #1H |
|
Williams |
|
Bakken |
|
|
21 |
%* |
|
|
30 |
|
|
|
2,652 |
|
|
|
833 |
|
Jerome Anderson 15-10 #1H |
|
Mountrail |
|
Bakken |
|
|
50 |
% |
|
|
30 |
|
|
|
3,115 |
|
|
|
1,146 |
|
Papineau Trust 17-20 #1H |
|
Williams |
|
Bakken |
|
|
43 |
%* |
|
|
29 |
|
|
|
3,042 |
|
|
|
971 |
|
Kalil 25-36 #1H |
|
Williams |
|
Bakken |
|
|
38 |
%* |
|
|
30 |
|
|
|
1,586 |
|
|
|
650 |
|
Liffrig 29-20 #1H |
|
Mountrail |
|
Three Forks |
|
|
72 |
% |
|
|
29 |
|
|
|
2,477 |
|
|
|
1,082 |
|
Owan-Nehring 27-34 |
|
Williams |
|
Bakken |
|
|
49 |
% |
|
|
30 |
|
|
|
2,513 |
|
|
|
1,089 |
|
Jackson 35-34 #1H |
|
Williams |
|
Bakken |
|
|
62 |
% |
|
|
30 |
|
|
|
3,540 |
|
|
|
907 |
|
State 36-1 #1H |
|
Williams |
|
Bakken |
|
|
16 |
%* |
|
|
30 |
|
|
|
3,807 |
|
|
|
1,516 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Averages |
|
|
2,939 |
|
|
|
1,085 |
|
|
|
|
* |
|
Rough Rider drilling participation agreement wells where our working interest is anticipated
to increase upon payout. |
|
** |
|
Excludes any days well was down for remediation. |
25
2011 Williston Basin Drilling and Completion Activity / 2011 Capital Budget
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FRAC |
|
|
IP |
|
|
30 DAY |
|
WELL NAME |
|
County |
|
|
OBJECTIVE |
|
|
~WI |
|
|
STAGES |
|
|
(Boe/d) |
|
|
Average (Boe/d)** |
|
Knoshaug 14-11 #1H |
|
Williams |
|
Bakken |
|
|
50 |
% |
|
|
36 |
|
|
|
4,443 |
|
|
NA |
|
Gibbins 1-12 #1H |
|
McKenzie |
|
Bakken |
|
|
55 |
% |
|
|
33 |
|
|
|
2,582 |
|
|
NA |
|
Swindle 16-9 #1H |
|
Roosevelt |
|
Bakken |
|
|
52 |
% |
|
|
19 |
|
|
|
1,065 |
|
|
NA |
|
Lloyd 34-3 #1H |
|
McKenzie |
|
Bakken |
|
|
29 |
%* |
|
|
31 |
|
|
|
4,030 |
|
|
|
1,456 |
|
Bratcher 10-3 #1H |
|
McKenzie |
|
Bakken |
|
|
91 |
% |
|
|
30 |
|
|
|
3,667 |
|
|
|
1,129 |
|
M. Macklin 15-22 #1H |
|
Williams |
|
Bakken |
|
|
89 |
% |
|
|
38 |
|
|
|
2,534 |
|
|
|
1,062 |
|
M. Olson 20-29 #1H |
|
Williams |
|
Bakken |
|
|
91 |
% |
|
|
38 |
|
|
|
2,080 |
|
|
|
1,007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Averages |
|
|
2,914 |
|
|
|
1,164 |
|
|
|
|
* |
|
Rough Rider drilling participation agreement wells where our working interest is anticipated
to increase upon payout. |
|
** |
|
Excludes any days well was down for remediation. |
During 2011, we anticipate spending approximately $582.1 million to drill and complete an
anticipated 65.7 net wells. Additionally, we anticipate spending approximately $27.4 million on
land. Finally, we anticipate spending approximately $83.2 million on support infrastructure to
expand our gathering systems in Williams and McKenzie Counties, North Dakota and to add additional
water disposal wells. See Item 7. Managements Discussion and Analysis of Financial Condition and
Results of Operations Capital Commitments Overview of Capital Activity.
Onshore Gulf Coast Province
Our Onshore Gulf Coast province is a high potential, multi-pay province that lends itself to
3-D seismic exploration due to its substantial structural and stratigraphic complexity. We believe
our established 3-D seismic exploration approach, combined with our exploration staffs extensive
experience and accumulated knowledge base in the Onshore Gulf Coast province provides us with
significant competitive advantages.
Since 2009, activity in the onshore Gulf Coast province has been significantly reduced due to
depressed natural gas prices and our allocation of capital to the Williston Basin, which is
predominately crude oil. During 2010, we completed two gross wells (2.0 net) in two attempts for a
completion rate of 100%. In 2010, we spent $16.4 million on drilling and land in our
Onshore Gulf Coast province, before the impact of asset sale proceeds. In 2011, we have no current
plans to drill in the Onshore Gulf Coast province.
Anadarko Basin Province
The Anadarko Basin is located in the Texas Panhandle and Western Oklahoma. We believe this
prolific natural gas producing province offers a combination of relatively lower risk exploration
and development opportunities in shallower horizons, as well as higher risk, but higher reserve
potential opportunities in the deeper sections that have been relatively under explored. In
addition, drilling economics in the Anadarko Basin are enhanced by the multi-pay nature of many of
the prospects, with secondary or tertiary targets serving as either incremental value or as
alternatives if the primary target zone is not productive.
As with our Onshore Gulf Coast province, our activity in the Anadarko Basin has been
significantly reduced since 2009. In 2010, we spent $0.7 million in the Anadarko Basin before the
impact of asset sale proceeds. In 2011, we anticipate spending $1.6 million to drill 6 gross (0.6
net) wells in the Anadarko Basin.
West Texas and Other Province
The Permian Basin of West Texas and Eastern New Mexico is a predominantly crude oil producing
province with generally longer life reserves than that of our onshore Gulf Coast.
26
During 2010, we completed 15 gross (2.6 net) Wolfberry wells in West Texas at a 100%
completion rate and spent a total of $4.8 million on drilling and land, before the
impact of asset sale proceeds. In the second quarter 2010, we completed the sale of a portion of
our proved developed reserves totaling approximately 0.6 MMboe. The primary assets remaining in
our West Texas province are approximately 2,050 net acres prospective for the Wolfberry. In
2011, we anticipate spending $3.1 million to drill 15 gross (1.8 net) wells in West Texas.
In the fourth quarter of 2010, we divested all of our acreage in the Powder River Basin in
Wyoming for proceeds totaling approximately $4.0 million.
Title to Properties
We believe we have satisfactory title, in all material respects, to substantially all of our
producing properties in accordance with standards generally accepted in the oil and natural gas
industry. Our properties are subject to royalty interests, standard liens incident to operating
agreements, liens for current taxes and other burdens, which we believe do not materially interfere
with the use of or affect the value of such properties. Substantially all of our proved crude oil
and natural gas properties are pledged as collateral for borrowings under our Senior Credit
Facility. See Item 7. Managements Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital Resources Senior Credit Facility and Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital
Resources Senior Notes.
Crude Oil and Natural Gas Reserves
Our estimated total net proved reserves of crude oil and natural gas as of December 31, 2010
are as follows:
Summary of Crude Oil and Natural Gas Reserves as of Fiscal-Year-End Based on Average Fiscal-Year
Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserves |
|
|
|
Crude oil |
|
|
NaturalGas |
|
|
Total |
|
|
|
(MMBbls) |
|
|
(Bcf) |
|
|
(MMBoe)(a) |
|
PROVED |
|
|
|
|
|
|
|
|
|
|
|
|
Developed: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
17.5 |
|
|
|
36.5 |
|
|
|
23.6 |
|
Undeveloped: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
34.7 |
|
|
|
51.3 |
|
|
|
43.2 |
|
|
|
|
|
|
|
|
|
|
|
TOTAL PROVED |
|
|
52.2 |
|
|
|
87.8 |
|
|
|
66.8 |
|
|
|
|
(a) |
|
Boe is defined as one barrel of oil equivalent determined using the ratio of six Mcf of
natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
Our internal control procedures require that our reserve report is prepared by a third party
engineering firm at the end of every year based on information provided by our Reservoir
Engineering Department. Our Chief Reservoir and Acquisitions Engineer reviews and approves the
reserve information compiled by our internal staff and is the technical person primarily
responsible for overseeing the preparation of our reserve estimates. He has a degree in Petroleum
Engineering from Texas A&M University and over 26 years experience in the industry, including SEC
compliance with respect to proved reserves. He is licensed professional engineer in the State of
Texas (PE 76121). Our internal staff of petroleum engineers, geoscience professionals and
petroleum landmen work closely with CGA, our third party reserve engineers, to ensure the
integrity, accuracy and timeliness of data furnished to CGA in their reserves estimation process.
CGA is a Texas Registered Engineering Firm (F-693). Our primary contact at CGA is Mr. W. Todd
Brooker, Vice President. Mr. Brooker is a State of Texas Licensed Professional Engineer (License
#83462).
All key parameters in the reserve information are reviewed and approved by our executive
officers. Our technical team meets regularly with representatives of CGA to review properties and
discuss the methods and assumptions used by CGA in their preparation of the year-end reserves
estimates. Our technical team and Chief Reservoir and Acquisitions Engineer also meets regularly
with our Executive Vice President Operations and our Executive Vice President Exploration to
review the methods and assumptions used by CGA in their preparation of the year-end reserves
estimates. A copy of the CGA reserve report and detailed reserve analysis are reviewed by our audit
committee with representatives of CGA and our internal technical staff before dissemination of the
information.
27
In accordance with applicable requirements of the SEC, estimates of our net proved reserves
and future net revenues are made using average prices at the beginning of each month in the
12-month period prior to the date of such reserve estimates and are held constant throughout the
life of the properties (except to the extent a contract specifically provides for escalation).
Estimated quantities of net proved reserves and future net revenues therefrom are affected by crude
oil and natural gas prices, which have fluctuated widely in recent years. See Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations Critical Accounting
Policies New Accounting Pronouncements.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and
their estimated values, including many factors beyond our control. The reserve data set forth in
the CGA report represents only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of crude oil and natural gas that cannot be measured in an
exact manner. The accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geologic interpretation and judgment. As a result, estimates of different
engineers, including those used by us, may vary. In addition, estimates of reserves are subject to
revision based upon actual production, results of future development and exploration activities,
prevailing crude oil and natural gas prices, operating costs and other factors. The revisions may
be material. Accordingly, reserve estimates are often different from the quantities of crude oil
and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the
assumptions upon which they are based. Our estimated net proved reserves, included in our SEC
filings, have not been filed with or included in reports to any other federal agency. See Item 1A.
Risk Factors Although our crude oil and natural gas reserve data is independently estimated,
these estimates may still prove to be inaccurate.
Estimates with respect to net proved reserves that may be developed and produced in the future
are often based upon volumetric calculations and upon analogy to similar types of reserves rather
than actual production history. Estimates based on these methods are generally less reliable than
those based on actual production history. Subsequent evaluation of the same reserves based upon
production history will result in variations in the estimated reserves that may be substantial.
Proved Undeveloped Reserves
Our total proved undeveloped (PUD) reserves as of December 31, 2010 were 43.2 MMBoe, or 65% of
our total proved reserves. Our PUD reserves as of December 31, 2009 were 17.5 MMBoe and represented
63% of our total proved reserves.
The increase in our year-end 2010 PUD reserves is attributable to both the increased level of
our drilling activity and the continued application of advance drilling and completion techniques
in the Williston Basin. During 2010, we had drilled and completed, were completing or were drilling 41.6 net wells versus 6.9 net wells in 2009. Our advanced techniques
incorporate drilling long lateral horizontal wellbores approximately 10,000 in length and
completing wells with multi-stage fracture stimulations ranging typically from 30 to 38 fracture
stimulations, which has improved our estimated ultimate recoveries. During 2010, we implemented
widespread application of our advanced drilling and completion techniques in Mountrail, Williams
and McKenzie Counties, North Dakota and drilled our initial well in Roosevelt County, Montana. In these areas, we were able to increase our level of PUD reserves.
Partially offsetting the above Williston Basin PUD reserve increases, we eliminated multiple PUD reserve
locations in the Onshore Gulf Coast province that were primarily conventional natural gas targets
that we currently do not anticipate drilling within the next five years. The PUD reserve locations
that we eliminated totaled 0.8 MMBoe.
Our PUD reserves also decreased due to the drilling of 33 gross PUD wells (13.2 net) during
2010. During the year, we spent approximately $95.9 million dollars converting 5.5 MMBoe from PUD
to proved developed producing reserves.
28
Reconciliation of Standardized Measure to Pre-tax PV10%
Pre-tax PV10% is the estimated present value of the future net revenues from our proved crude
oil and natural gas reserves before income taxes discounted using a 10% discount rate. Pre-tax
PV10% is considered a non-GAAP financial measure under SEC regulations because it does not include
the effects of future income taxes, as is required in computing the standardized measure of
discounted future net cash flows. We believe that pre-tax PV10%
is an important measure that can be used to evaluate the relative significance of our crude
oil and natural gas properties and that pre-tax PV10% is widely used by securities analysts and
investors when evaluating oil and natural gas companies. Because many factors that are unique to
each individual company impact the amount of future income taxes to be paid, the use of a pre-tax
measure provides greater comparability of assets when evaluating companies. We believe that most
other companies in the oil and natural gas industry calculate pre-tax PV10% on the same basis.
Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net
cash flows but without deducting income taxes. The table below provides a reconciliation of our
standardized measure of discounted future net cash flows to our pre-tax PV10% value (in millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Standardized measure of discounted future net cash flows |
|
$ |
866.1 |
|
|
$ |
246.5 |
|
|
$ |
279.3 |
|
Add present value of future income tax discounted at 10% |
|
|
242.6 |
|
|
|
7.6 |
|
|
|
8.7 |
|
|
|
|
|
|
|
|
|
|
|
Pre-tax PV10% |
|
$ |
1,108.7 |
|
|
$ |
254.1 |
|
|
$ |
288.0 |
|
|
|
|
|
|
|
|
|
|
|
29
Drilling Activities
We drilled and completed, or participated in the drilling and completion of, the following
wells during the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Exploratory wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
|
0 |
|
|
|
0.0 |
|
|
|
0 |
|
|
|
0.0 |
|
|
|
4 |
|
|
|
1.3 |
|
Crude oil |
|
|
1 |
|
|
|
1.0 |
|
|
|
1 |
|
|
|
0.1 |
|
|
|
1 |
|
|
|
0.8 |
|
Non-productive |
|
|
0 |
|
|
|
0.0 |
|
|
|
1 |
|
|
|
0.2 |
|
|
|
2 |
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
1 |
|
|
|
1.0 |
|
|
|
2 |
|
|
|
0.3 |
|
|
|
7 |
|
|
|
3.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
|
7 |
|
|
|
2.1 |
|
|
|
1 |
|
|
|
0.6 |
|
|
|
9 |
|
|
|
4.5 |
|
Crude oil |
|
|
125 |
|
|
|
31.1 |
|
|
|
51 |
|
|
|
6.9 |
|
|
|
52 |
|
|
|
7.8 |
|
Non-productive |
|
|
0 |
|
|
|
0.0 |
|
|
|
0 |
|
|
|
0.0 |
|
|
|
0 |
|
|
|
0.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
132 |
|
|
|
33.2 |
|
|
|
52 |
|
|
|
7.5 |
|
|
|
61 |
|
|
|
12.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present Activities
As of December 31, 2010, we had seven operated drilling rigs in the Williston Basin. Four
drilling rigs were drilling development locations representing 2.2 net wells, two drilling rigs
were in the process of rigging down and one drilling rig was in the process of rigging up. At
year-end, we also had 17 non-operated wells drilling in the Williston Basin representing 0.5 net
wells. We had 11 operated wells in the Williston Basin waiting on completion representing 7.6 net
wells and one operated well in the Williston Basin fracing representing 0.3 net wells. Finally, we
had 24 non-operated Williston Basin wells waiting on completion representing 1.4 net wells.
We do not own drilling rigs and all of our drilling activities have been conducted by
independent contractors or by industry participant operators under standard drilling contracts.
Delivery Commitments
We have committed to
deliver all of our natural gas from our lands and leases in Williams
County, North Dakota for the next seven years to a single purchaser. We must deliver a minimum of
2,500 mcf per day for the first year and 5,000 mcf per day for the subsequent four years. We will
pay a
penalty for volume deficiencies except in certain circumstances. We will receive 70% of the
purchasers proceeds minus certain adjustments. The purchaser is required to pay for all
facilities required to receive our gas from existing wells and the entire cost to connect for
subsequent wells located within two miles of the purchasers gathering system. For subsequent
wells located more than two miles from the purchasers gathering system, the purchaser may
elect to
either pay the cost to connect for the first two miles and require us to pay the cost to connect
for the remainder or not to connect the well. If the purchaser elects not to connect the
subsequent well, we can request the well and any others within that spacing unit be released from
the terms of the agreement. Additionally, contingent upon completion of pipelines from the
Williston Basin to Guernsey, Wyoming and Cushing, Oklahoma, we have entered into agreements with a
marketing company to
deliver an average of 5,000 barrels of oil per day and 10,000 barrels of oil per day, respectively
for five years. We have the right to terminate
this agreement if the pipelines are not in service by December 31, 2012 and December 31, 2013,
respectively. We will pay a penalty for
volume deficiencies except in certain circumstances. We will receive NYMEX near month WTI minus
certain adjustments and a marketing fee. We have determined that we will have sufficient production
to meet these commitments.
30
Productive Wells and Acreage
Productive Wells
The following table sets forth our ownership interest at December 31, 2010 in productive crude
oil and natural gas wells in the areas indicated. Wells are classified as crude oil or natural gas
according to their predominant production stream. Gross wells are the total number of producing
wells in which we have an interest, and net wells are determined by multiplying gross wells by our
average working interest.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
Crude oil |
|
|
Total |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Williston Basin |
|
|
0 |
|
|
|
0.0 |
|
|
|
237 |
|
|
|
61.0 |
|
|
|
237 |
|
|
|
61.0 |
|
Onshore Gulf Coast |
|
|
68 |
|
|
|
40.4 |
|
|
|
17 |
|
|
|
4.1 |
|
|
|
85 |
|
|
|
44.5 |
|
Anadarko Basin |
|
|
79 |
|
|
|
22.1 |
|
|
|
10 |
|
|
|
1.5 |
|
|
|
89 |
|
|
|
23.6 |
|
West Texas and Other |
|
|
0 |
|
|
|
0.0 |
|
|
|
31 |
|
|
|
7.6 |
|
|
|
31 |
|
|
|
7.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
147 |
|
|
|
62.5 |
|
|
|
295 |
|
|
|
74.2 |
|
|
|
442 |
|
|
|
136.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive wells consist of producing wells and wells capable of production, including wells
waiting on pipeline connection. Wells that are completed in more than one producing horizon are
counted as one well.
Acreage
Undeveloped acreage includes leased acres on which wells have not been drilled or completed to
a point that would permit the production of commercial quantities of crude oil and natural gas,
regardless of whether or not such acreage contains proved reserves. The following table sets forth
the approximate developed and undeveloped acreage that we held as leasehold interest at December
31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed(a) |
|
|
Undeveloped(a) |
|
|
Total |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Williston Basin |
|
|
131,531 |
|
|
|
87,273 |
|
|
|
469,070 |
|
|
|
277,036 |
|
|
|
600,601 |
|
|
|
364,309 |
|
Onshore Gulf Coast |
|
|
21,627 |
|
|
|
9,077 |
|
|
|
5,016 |
|
|
|
2,985 |
|
|
|
26,643 |
|
|
|
12,062 |
|
Anadarko Basin |
|
|
61,529 |
|
|
|
17,498 |
|
|
|
7,136 |
|
|
|
5,110 |
|
|
|
68,665 |
|
|
|
22,608 |
|
West Texas and Other |
|
|
11,928 |
|
|
|
2,316 |
|
|
|
6,508 |
|
|
|
756 |
|
|
|
18,436 |
|
|
|
3,072 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
226,615 |
|
|
|
116,164 |
|
|
|
487,730 |
|
|
|
285,887 |
|
|
|
714,345 |
|
|
|
402,051 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Does not include acreage for which assignments have not been received. |
All of our leases for undeveloped acreage summarized in the preceding table will expire at the
end of their respective primary terms unless we renew the existing leases, we establish production
from the acreage, or some other savings clause is exercised. The following table sets forth the
minimum remaining lease terms for our gross and net undeveloped acreage.
|
|
|
|
|
|
|
|
|
|
|
Acres Expiring |
|
Twelve Months Ending: |
|
Gross |
|
|
Net |
|
December 31, 2011 |
|
|
110,129 |
|
|
|
54,477 |
|
December 31, 2012 |
|
|
159,025 |
|
|
|
95,979 |
|
December 31, 2013 |
|
|
155,224 |
|
|
|
81,771 |
|
December 31, 2014 |
|
|
36,045 |
|
|
|
28,806 |
|
December 31, 2015 |
|
|
7,358 |
|
|
|
4,928 |
|
Thereafter |
|
|
19,949 |
|
|
|
19,926 |
|
|
|
|
|
|
|
|
Total |
|
|
487,730 |
|
|
|
285,887 |
|
|
|
|
|
|
|
|
In addition, as of December 31, 2010, we had mineral interests covering approximately 13,408
gross and 2,100 net acres including 264 net acres in the Williston Basin. The mineral acres will
continue into perpetuity and will not expire.
31
Sales Volumes, Prices and Production Costs
The
following table sets forth our sales volumes for the Williston Basin.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Sales volumes(a): |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil volumes (MBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin |
|
|
2,026 |
|
|
|
607 |
|
|
|
285 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas volumes (MMcf) |
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin |
|
|
940 |
|
|
|
163 |
|
|
|
50 |
|
The following table
sets forth the average prices we received before
hedging, the average prices we received including hedging settlement gains (losses), the average
price including hedging settlements and unrealized gains (losses) and average production costs
associated with our sale of crude oil and natural gas for the periods indicated. We account for our
hedges using mark-to-market accounting, which requires that we record both derivative settlements
and unrealized gains (losses) to the consolidated statement of operations within a single
income statement line item. We have elected to include both derivative settlements and
unrealized gains (losses) within revenue.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average crude oil prices based on sales volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil price (per Bbl) |
|
$ |
71.08 |
|
|
$ |
54.79 |
|
|
$ |
89.06 |
|
Crude oil price including derivative settlement gains (losses) (per Bbl) |
|
$ |
70.87 |
|
|
$ |
53.99 |
|
|
$ |
84.63 |
|
Crude oil price including derivative settlements and unrealized gains
(losses) (per Bbl) |
|
$ |
64.55 |
|
|
$ |
48.65 |
|
|
$ |
89.79 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas prices based on sales volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price (per Mcf) |
|
$ |
5.23 |
|
|
$ |
4.01 |
|
|
$ |
9.21 |
|
Natural gas price including derivative settlement gains (losses)
(per Mcf) |
|
$ |
6.02 |
|
|
$ |
5.71 |
|
|
$ |
9.08 |
|
Natural gas price including derivative settlements and unrealized gains
(losses) (per Mcf) |
|
$ |
6.16 |
|
|
$ |
5.21 |
|
|
$ |
9.48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average equivalent prices based on sales volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil equivalent price (per Boe) |
|
$ |
60.84 |
|
|
$ |
37.97 |
|
|
$ |
65.50 |
|
Oil equivalent price including derivative settlement gains (losses)
(per Boe) |
|
$ |
61.90 |
|
|
$ |
43.19 |
|
|
$ |
63.62 |
|
Oil equivalent price including derivative settlements and unrealized
gains (losses) (per Boe) |
|
$ |
57.43 |
|
|
$ |
39.12 |
|
|
$ |
66.84 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average production costs (per Boe) based on sales volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses (includes costs for operating and maintenance
and expensed workovers) |
|
$ |
6.03 |
|
|
$ |
7.61 |
|
|
$ |
5.89 |
|
Ad valorem taxes |
|
$ |
0.30 |
|
|
$ |
0.56 |
|
|
$ |
0.58 |
|
Production taxes |
|
$ |
5.88 |
|
|
$ |
2.84 |
|
|
$ |
2.81 |
|
|
|
|
(a) |
|
Sales volumes for 2010 and 2009 exclude 29,654 and 16,475 barrels of crude oil produced
during the year and added to inventory during the respective period. Ending inventory at year
end 2008 was not material. |
32
|
|
|
Item 3. |
|
Legal Proceedings |
We are, from time to time, party to certain lawsuits and claims arising in the ordinary course
of business. While the outcome of lawsuits and claims cannot be predicted with certainty,
management does not expect these matters to have a materially adverse effect on our financial
condition, results of operations or cash flows.
As of December 31, 2010, there are no known environmental or other regulatory matters related
to our operations that are reasonably expected to result in a material liability to us. Compliance
with environmental laws and regulations has not had, and is not expected to have, a material
adverse effect on our capital expenditures.
|
|
|
Item 4. |
|
Removed and Reserved. |
Executive Officers of the Registrant
Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to
Form 10-K, the following information is included in Part I of this report. The following are our
executive officers as of February 25, 2010.
|
|
|
|
|
Name |
|
Age |
|
Position |
Ben M. Brigham |
|
51 |
|
Chief Executive Officer, President and Chairman |
Eugene B. Shepherd, Jr. |
|
52 |
|
Executive Vice President and Chief Financial Officer |
David T. Brigham |
|
50 |
|
Executive Vice President Land and Administration and Director |
A. Lance Langford |
|
48 |
|
Executive Vice President Operations |
Jeffery E. Larson |
|
52 |
|
Executive Vice President Exploration |
Ben M. Bud Brigham has served as our Chief Executive Officer, President and Chairman of the
Board since we were founded in 1990. From 1984 to 1990, Mr. Brigham served as an exploration
geophysicist with Rosewood Resources, an independent oil and gas exploration and production
company. Mr. Brigham began his career in Houston as a seismic data processing geophysicist for
Western Geophysical, Inc. a provider of 3-D seismic services, after earning his B.S. in Geophysics
from the University of Texas at Austin. Mr. Brigham is the brother of David T. Brigham, Executive
Vice President Land and Administration.
Eugene B. Shepherd, Jr. has served as Executive Vice President and Chief Financial Officer
since October 2003, and previously served as Chief Financial Officer from June 2002 to October
2003. Mr. Shepherd has approximately 27 years of financial and operational experience in the energy
industry. Prior to joining us, Mr. Shepherd served as Integrated Energy Managing Director for the
investment banking division of ABN AMRO Bank, where he executed merger and acquisition advisory,
capital markets and syndicated loan transactions for energy companies. Prior to joining ABN AMRO,
Mr. Shepherd spent fourteen years as an investment banker for Prudential Securities Incorporated,
Stephens Inc. and Merrill Lynch Capital Markets. Mr. Shepherd worked as a petroleum engineer for
over four years for both Amoco Production Company and the Railroad Commission of Texas. He holds a
B.S. in Petroleum Engineering and an MBA, both from the University of Texas at Austin.
David T. Brigham joined us in 1992 and has served as a Director since May 2003 and as
Executive Vice President Land and Administration since June 2002. Mr. Brigham served as Senior
Vice President Land and Administration from March 2001 to June 2002, Vice President Land and
Administration from February 1998 to March 2001, as Vice President Land and Legal from 1994
until February 1998 and as Corporate Secretary from February 1998 to September 2002. From 1987 to
1992, Mr. Brigham worked as an attorney in the energy section with Worsham, Forsythe, Sampels &
Wooldridge. For a brief period of time before attending law school, Mr. Brigham was a landman for
Wagner & Brown Oil and Gas Producers, an independent oil and gas exploration and production
company. Mr. Brigham holds a B.B.A. in Petroleum Land Management from the University of Texas and a
J.D. from Texas Tech School of Law. Mr. Brigham is the brother of Ben M. Brigham, Chief Executive
Officer, President and Chairman of the Board.
33
A. Lance Langford joined us in 1995 as Manager of Operations, served as Vice President -
Operations from January 1997 to March 2001, served as Senior Vice President Operations from
March 2001 to September 2003 and has served as Executive Vice President Operations since
September 2003. From 1987 to 1995, Mr. Langford served in various engineering capacities with
Meridian Oil Inc., handling a variety of reservoir, production and drilling responsibilities. Mr.
Langford holds a B.S. in Petroleum Engineering from Texas Tech University.
Jeffery E. Larson joined us in 1997 and was Vice President Exploration from August 1999 to
March 2001, Senior Vice President Exploration from March 2001 to September 2003 and has served
as Executive Vice President Exploration since September 2003. Prior to joining us, Mr. Larson
was an explorationist in the Offshore Department of Burlington Resources, a large independent
exploration company, where he was responsible for generating exploration and development drilling
opportunities. Mr. Larson worked at Burlington from 1990 to 1997 in various roles of
responsibility. Prior to Burlington, Mr. Larson spent five years at Exxon as a Production Geologist
and Research Scientist. He holds a B.S. in Earth Science from St. Cloud State University in
Minnesota and a M.S. in Geology from the University of Montana.
PART II
|
|
|
Item 5. |
|
Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities |
Price Range of Common Stock, Performance Graph, and Dividend Policy
Our common stock commenced trading on the NASDAQ Global Select Market (formerly the NASDAQ
National Market) on May 8, 1997 under the symbol BEXP. The following table sets forth the high
and low intra-day sales prices per share of our common stock for the periods indicated on the
NASDAQ Global Select Market for the periods indicated. The sales information below reflects
inter-dealer prices, without retail mark-ups, mark-downs or commissions and may not necessarily
represent actual transactions.
|
|
|
|
|
|
|
|
|
|
|
High |
|
|
Low |
|
2009: |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
4.25 |
|
|
$ |
1.04 |
|
Second Quarter |
|
|
4.30 |
|
|
|
1.60 |
|
Third Quarter |
|
|
10.61 |
|
|
|
2.50 |
|
Fourth Quarter |
|
|
14.93 |
|
|
|
7.99 |
|
2010: |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
18.00 |
|
|
$ |
12.58 |
|
Second Quarter |
|
|
21.15 |
|
|
|
13.45 |
|
Third Quarter |
|
|
19.15 |
|
|
|
14.18 |
|
Fourth Quarter |
|
|
28.15 |
|
|
|
18.55 |
|
The closing market price of our common stock on February 23, 2011 was $33.86 per share. As of
February 23, 2011, there were an estimated 145 record owners of our common stock.
34
The following graph is a comparison of cumulative total returns. It assumes that $100 was
invested in our common stock, the NASDAQ Composite Index, and the S&P Oil & Gas Exploration and
Production Index at the end of 2005 and remained invested through year-end 2010. The Indices and
the graph were prepared by an independent third party. The NASDAQ Composite Index is calculated
using the over 3,000 companies which trade on The NASDAQ Stock Market, including both domestic and
foreign companies. The S&P Oil & Gas Exploration and Production Index (SPSIOP) represents the oil
and gas exploration and production sub-industry portion of the S&P Total Market Index.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Brigham Exploration Company, The NASDAQ Composite Index
And The S&P Oil & Gas Exploration & Production Index
|
|
|
* |
|
$100 invested on 12/31/05 in stock or index, including reinvestment of dividends. Fiscal
years ending
December 31. |
No dividends have been declared or paid on our common stock to date. We intend to retain all
future earnings for the development of our business. Our Senior Credit Facility and our Senior
Notes restrict our ability to pay dividends on our common stock.
35
Securities Authorized for Issuance under Equity Compensation Plans
The following table includes information regarding our equity compensation plans as of the
year ended December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
|
|
|
|
|
|
|
|
|
Securities |
|
|
|
Number of |
|
|
|
|
|
|
Remaining |
|
|
|
Securities to be |
|
|
|
|
|
|
Available for |
|
|
|
Issued upon |
|
|
Weighted- |
|
|
Future Issuance |
|
|
|
Exercise of |
|
|
Average Price of |
|
|
Under Equity |
|
|
|
Outstanding |
|
|
Outstanding |
|
|
Compensation |
|
Plan Category |
|
Options |
|
|
Options |
|
|
Plans |
|
Equity compensation
plans approved by
security holders(a) |
|
|
741,037 |
|
|
$ |
8.41 |
|
|
|
2,262,815 |
|
Equity compensation
plans not approved
by security holders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
741,037 |
|
|
$ |
8.41 |
|
|
|
2,262,815 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Does not include 530,883 shares of restricted stock issued and outstanding at December 31,
2010. |
Issuer Purchases of Equity Securities
In 2010, we elected to allow employees to deliver shares of vested restricted stock with a
fair market value equal to their federal, state and local tax withholding amounts on the date of
issue in lieu of cash payment.
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
|
Average Price |
|
Period |
|
Shares Purchased |
|
|
Paid per Share |
|
October 2010 |
|
|
2,520 |
|
|
$ |
21.01 |
|
|
|
|
|
|
|
|
Total |
|
|
2,520 |
|
|
|
21.01 |
|
|
|
|
|
|
|
|
|
|
|
Item 6. |
|
Selected Consolidated Financial Data |
This section presents our selected consolidated financial data and should be read in
conjunction with Item 7. Managements Discussion and Analysis of Financial Condition and Results
of Operations and our consolidated financial statements and related notes included in Item 8.
Financial Statements and Supplementary Data. The selected consolidated financial data in this
section is not intended to replace our consolidated financial statements.
36
We derived the statement of operations data and statement of cash flows data for the years
ended December 31, 2010, 2009 and 2008, and balance sheet data as of December 31, 2010 and 2009
from the audited consolidated financial statements included in this report. We derived the
statement of operations data and statement of cash flows data for the years ended December 31, 2007
and 2006 and the balance sheet data as of December 31, 2008, 2007 and 2006, from our accounting
books and records.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands, except per share information) |
|
Statement of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas sales |
|
$ |
179,279 |
|
|
$ |
68,192 |
|
|
$ |
125,108 |
|
|
$ |
120,557 |
|
|
$ |
102,835 |
|
Gain (loss) on derivatives, net |
|
|
(10,066 |
) |
|
|
2,064 |
|
|
|
2,548 |
|
|
|
(1,664 |
) |
|
|
3,335 |
|
Support infrastructure revenue |
|
|
489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other revenue |
|
|
20 |
|
|
|
88 |
|
|
|
132 |
|
|
|
88 |
|
|
|
127 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
169,722 |
|
|
|
70,344 |
|
|
|
127,788 |
|
|
|
118,981 |
|
|
|
106,297 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
|
18,651 |
|
|
|
14,655 |
|
|
|
12,363 |
|
|
|
10,704 |
|
|
|
10,701 |
|
Production taxes |
|
|
17,313 |
|
|
|
5,098 |
|
|
|
5,374 |
|
|
|
2,541 |
|
|
|
4,021 |
|
Support infrastructure expenses |
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
12,943 |
|
|
|
9,243 |
|
|
|
9,557 |
|
|
|
9,276 |
|
|
|
7,887 |
|
Depletion of crude oil and natural
gas properties |
|
|
58,195 |
|
|
|
32,054 |
|
|
|
53,498 |
|
|
|
59,079 |
|
|
|
46,386 |
|
Impairment of crude oil and natural
gas properties |
|
|
|
|
|
|
114,781 |
|
|
|
237,180 |
|
|
|
6,505 |
|
|
|
|
|
Depreciation and amortization |
|
|
1,704 |
|
|
|
812 |
|
|
|
629 |
|
|
|
613 |
|
|
|
537 |
|
Loss on inventory valuation |
|
|
|
|
|
|
2,196 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount on asset
retirement obligations |
|
|
422 |
|
|
|
421 |
|
|
|
361 |
|
|
|
379 |
|
|
|
317 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
109,278 |
|
|
|
179,260 |
|
|
|
318,962 |
|
|
|
89,097 |
|
|
|
69,849 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
60,444 |
|
|
|
(108,916 |
) |
|
|
(191,174 |
) |
|
|
29,884 |
|
|
|
36,448 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
1,198 |
|
|
|
578 |
|
|
|
191 |
|
|
|
654 |
|
|
|
1,207 |
|
Interest expense, net |
|
|
(11,448 |
) |
|
|
(16,431 |
) |
|
|
(14,495 |
) |
|
|
(14,622 |
) |
|
|
(9,688 |
) |
Gain loss on derivatives, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,213 |
|
Loss on early redemption of
Senior Notes |
|
|
(11,308 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense) |
|
|
5,094 |
|
|
|
1,544 |
|
|
|
530 |
|
|
|
1,022 |
|
|
|
1,352 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense) |
|
|
(16,464 |
) |
|
|
(14,309 |
) |
|
|
(13,774 |
) |
|
|
(12,946 |
) |
|
|
(3,916 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
and cumulative effect of change in
accounting principle |
|
|
43,980 |
|
|
|
(123,225 |
) |
|
|
(204,948 |
) |
|
|
16,938 |
|
|
|
32,532 |
|
Income tax benefit (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred |
|
|
(1,084 |
) |
|
|
233 |
|
|
|
42,701 |
|
|
|
(6,728 |
) |
|
|
(12,744 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,084 |
) |
|
|
233 |
|
|
|
42,701 |
|
|
|
(6,728 |
) |
|
|
(12,744 |
) |
Net income (loss) available to
common stockholders |
|
$ |
42,896 |
|
|
$ |
(122,992 |
) |
|
$ |
(162,247 |
) |
|
$ |
10,210 |
|
|
$ |
19,788 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
available to common shareholders: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.39 |
|
|
$ |
(1.74 |
) |
|
$ |
(3.57 |
) |
|
$ |
0.23 |
|
|
$ |
0.44 |
|
Diluted |
|
|
0.38 |
|
|
|
(1.74 |
) |
|
|
(3.57 |
) |
|
|
0.22 |
|
|
|
0.43 |
|
Weighted average shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
111,355 |
|
|
|
70,569 |
|
|
|
45,441 |
|
|
|
45,110 |
|
|
|
45,017 |
|
Diluted |
|
|
113,308 |
|
|
|
70,569 |
|
|
|
45,441 |
|
|
|
45,531 |
|
|
|
45,597 |
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands) |
|
Statement of Cash Flows Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
144,520 |
|
|
$ |
51,750 |
|
|
$ |
69,630 |
|
|
$ |
90,449 |
|
|
$ |
88,687 |
|
Investing activities |
|
|
(556,211 |
) |
|
|
(164,620 |
) |
|
|
(179,866 |
) |
|
|
(99,093 |
) |
|
|
(171,747 |
) |
Financing activities |
|
|
394,653 |
|
|
|
113,608 |
|
|
|
136,416 |
|
|
|
18,207 |
|
|
|
83,385 |
|
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
23,743 |
|
|
$ |
40,781 |
|
|
$ |
40,043 |
|
|
$ |
13,863 |
|
|
$ |
4,300 |
|
Investments |
|
|
223,991 |
|
|
|
80,093 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas properties,
using the full cost method of
accounting, net |
|
|
669,356 |
|
|
|
330,733 |
|
|
|
404,839 |
|
|
|
510,207 |
|
|
|
485,525 |
|
Total assets |
|
|
1,085,401 |
|
|
|
498,256 |
|
|
|
489,056 |
|
|
|
548,428 |
|
|
|
522,587 |
|
Long-term debt |
|
|
300,000 |
|
|
|
158,968 |
|
|
|
303,730 |
|
|
|
168,492 |
|
|
|
149,334 |
|
Series A preferred stock, mandatorily
redeemable (a) |
|
|
|
|
|
|
10,101 |
|
|
|
10,101 |
|
|
|
10,101 |
|
|
|
10,101 |
|
Total stockholders equity |
|
|
593,270 |
|
|
|
264,283 |
|
|
|
121,269 |
|
|
|
279,027 |
|
|
|
266,015 |
|
|
|
|
(a) |
|
At year-end 2009, our Series A preferred stock was classified as a current liability as it
was scheduled to be redeemed in 2010. Our Series A preferred stock was redeemed in the second
quarter 2010. |
|
|
|
Item 7. |
|
Managements Discussion and Analysis of Financial Condition and Results of Operations |
Statements in the following discussion may be forward-looking and involve risk and
uncertainty. The following discussion should be read in conjunction with our Consolidated Financial
Statements and Notes hereto.
Sources of Our Revenues
We derive our revenues from the sale of crude oil and natural gas that is produced from our
properties. Revenues are a function of the production volumes sold and the prevailing market prices
at the time of sale.
To achieve more predictable cash flows and to reduce our exposure to downward price
fluctuations, we utilize derivative instruments to hedge future sales prices on a portion of our
oil and natural gas production. Our current strategy is to hedge up to 100% of our proved developed
producing (PDP) oil volumes and up to 50% of the forecasted oil volumes associated with our
Williston Basin drilling program for the upcoming 24 months. The use of certain types of derivative
instruments may prevent us from realizing the benefit of upward price movements. See Item 1A. Risk
Factors Our hedging activities may prevent us from benefiting from price increases and may
expose us to other risks.
Components of Our Cost Structure
Production Costs are the day-to-day costs we incur to bring hydrocarbons out of the ground and
to the market combined with the daily costs we incur to maintain our producing properties. This
includes lease operating expenses and production taxes.
|
|
|
Lease operating expenses are generally comprised of several components including: the
cost of labor and supervision to operate our wells and related equipment; repairs and
maintenance; fluid treatment and disposal; related materials, supplies, and fuel; and
insurance applicable to our wells and related facilities and equipment. Lease operating
expenses also include the cost for expensed workovers. Lease operating expenses are driven
in part by the type of commodity produced, the level of workover activity and the
geographical location of the properties. |
|
|
|
Lease operating expenses also include ad valorem taxes, which are imposed by local
taxing authorities such as school districts, cities, and counties or boroughs. The amount
of tax we pay is based on a percent of value of the property assessed or determined by the
taxing authority on an annual basis. When crude oil and natural
gas prices rise, the value of our underlying property interests increase, which results in
higher ad valorem taxes. |
38
|
|
|
In the U.S., there are a variety of state and federal taxes levied on the production of
crude oil and natural gas. These are commonly grouped together and referred to as
production taxes. The majority of our production tax expense is based on a percent of gross
value realized at the wellhead at the time the production is sold or removed from the
lease. As a result, our production tax expense increases when crude oil and gas prices rise
or when production from an area increases. |
|
|
|
Historically, taxing authorities have occasionally encouraged the oil and natural gas
industry to explore for new crude oil and natural gas reserves, or to develop high cost
reserves, through reduced tax rates or tax credits. These incentives have been narrow in
scope and short-lived. A small number of our wells have qualified for reduced production
taxes because they were discoveries based on the use of 3-D seismic or they are high cost
wells. |
Depreciation, Depletion and Amortization is the systematic expensing of the capital costs
incurred to acquire, explore and develop crude oil and natural gas. As a full cost company, we
capitalize all direct costs associated with our exploration and development efforts, including a
portion of our interest and certain general and administrative costs, and apportion these costs to
each unit of production sold through depletion expense. Generally, if reserve quantities are
revised up or down, our depletion rate per unit of production will change inversely. When the
depreciable capital cost base increases or decreases, the depletion rate will move in the same
direction.
Asset Retirement Accretion Expense is the systematic, monthly accretion of future abandonment
costs of tangible assets such as wells, service assets, pipelines, and other facilities.
General and Administrative Expense includes payroll and benefits for our corporate staff,
costs of maintaining our headquarters, managing our production and development operations and legal
compliance. We capitalize general and administrative costs directly related to prospect generation
and our exploration activities.
Interest. We have relied on our Senior Credit Facility to fund our short-term liquidity
(working capital) and a portion of our long-term financing needs. The interest rate that we pay on
our Senior Credit Facility correlates with both fluctuations in interest rates and the amount
outstanding under the facility. We pay a fixed interest rate on our Senior Notes. We expect to
continue to incur interest expense as we continue to use debt to fund a portion of our capital
expenditures. We capitalize interest directly related to our unevaluated properties and certain
properties under development, which are not being amortized.
Income Taxes. We are generally subject to a 35% federal income tax rate. For income tax
purposes, we are allowed deductions for accelerated depreciation, depletion, intangible drilling
costs, and state taxes. Through 2010, all of our federal and state income taxes were deferred.
Capital Commitments
Our primary needs for cash are to fund our capital expenditure program, our working capital
obligations and for the repayment of contractual obligations. In the future, cash will also be
required to fund our capital expenditures for the exploration and development of properties
necessary to offset the inherent declines in production and proven reserves that are typical in an
extractive industry like ours and also to hold acreage that would otherwise expire if not drilled.
Future success in growing reserves and production will be highly dependent on our access to cost
effective capital resources and our success in economically finding and producing additional crude
oil and natural gas reserves. Funding for our exploration and development of crude oil and natural
gas activities and the repayment of our contractual obligations may be provided by any combination
of cash flow from operations, cash on our balance sheet, the unused committed borrowing capacity
under our Senior Credit Facility, reimbursements of prior land and seismic costs by third parties
who participate in our projects, and the sale of interests in projects and properties or
alternative financing sources as discussed in - Contractual Obligations and - Liquidity and
Capital Resources. Cash flows from operations and the unused committed borrowing capacity under
our Senior Credit Facility fund our working capital obligations.
39
Overview of Capital Activity
The application of advanced drilling and completion technologies in the Williston Basin and
the associated improvements in well economics as well as the commodity price advantage of crude oil
relative to natural gas has led us to increase both the total amount of capital expended and the
percentage allocation of our capital budget to the Williston Basin and to decrease our spending in
our other conventional natural gas focused provinces.
In October 2009, we completed a public offering of common stock and raised $168.3 million in
net proceeds in order to pre-fund an increased level drilling activity in 2010. Our preliminary
2010 capital budget announced in October 2009, concurrent with the equity offering, was estimated
to be $175.8 million. We estimated that we would have four drilling rigs running throughout 2010
in the Williston Basin and would drill 24 net Bakken and Three Forks wells.
In April 2010, we completed a public offering of common stock and raised $277.5 million in net
proceeds in order to pre-fund a further acceleration in the Williston Basin. Our revised 2010
capital budget announced concurrent with the equity offering, was estimated to be $293.9 million.
We estimated that we would add an incremental operated drilling rig every four months beginning May
2010 and would have eight operated rigs running in the Williston Basin by May 2011 and would
therefore drill 31 net wells in the basin during 2010. Approximately $37.8 million of the
aforementioned capital budget would be used to fund the construction of support infrastructure.
In August 2010, we revised our 2010 capital budget largely as a result of several large
acreage acquisitions, which increased our acreage in the Williston Basin by approximately 52,800
net acres. Our revised capital budget announced in August 2010 was estimated to be approximately
$404.0 million and included approximately 38 net Williston Basin wells and $95.7 million for land.
In September 2010, we issued $300 million in Senior Notes due 2018 to fund the tender offer
for and redemption of our 9 5/8% Senior Notes due in 2014 and to pre-fund our 2011 capital budget
and for general corporate purposes.
In November 2010, we revised our 2010 capital budget to $466.1 million largely as a result of
the expectation of drilling and completing 45 net Williston Basin wells. We also increased our
land budget and our support infrastructure budget by approximately $19 million and $3
million, respectively. See Capital Expenditures for a discussion of our 2011 budget.
Capital Expenditures
The timing of most of our capital expenditures is discretionary because we operate the
majority of our wells. During 2010, we executed an agreement with a drilling contractor to enter
into commitments for two walking drilling rigs for a three year period beginning upon their
delivery date, which is anticipated to be in the first quarter 2012. Other than the aforementioned
obligations, we have no material long-term capital expenditure commitments. Consequently, we have
a significant degree of flexibility to adjust the level of our capital expenditures as
circumstances warrant. Our capital expenditure program includes the following:
|
|
|
cost of acquiring and maintaining our lease acreage position and our seismic resources; |
|
|
|
cost of drilling and completing new crude oil and natural gas wells; |
|
|
|
cost of installing and maintaining new support infrastructure; |
|
|
|
cost of maintaining, repairing and enhancing existing crude oil and natural gas wells; |
|
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|
cost related to plugging and abandoning unproductive or uneconomic wells; and |
|
|
|
indirect costs related to our exploration activities, including payroll and other
expenses attributable to our exploration professional staff. |
The capital that funds our drilling activities is allocated to individual prospects based on
the value potential of a prospect, as measured by a risked net present value analysis. We start
each year with a budget and re-evaluate this budget monthly. The primary factors that impact this
value creation measure include forecasted commodity prices, drilling and completion costs, and a
prospects risked reserve size and risked initial producing rate. Other factors
that are also monitored throughout the year that influence the amount and timing of our
planned expenditures include the level of production from our existing crude oil and natural gas
properties, the availability of drilling and completion services, and the success and resulting
production of our newly drilled wells. The outcome of our monthly analysis results in a
reprioritization of our exploration and development drilling schedule to ensure that we are
optimizing our capital expenditure plan.
40
The final determination with respect to our 2011 budgeted expenditures will depend on a number
of factors, including:
|
|
|
production from our existing producing wells; |
|
|
|
the results of our current exploration and development drilling efforts; |
|
|
|
economic conditions at the time of drilling; |
|
|
|
industry conditions at the time of drilling, including the availability of drilling and
completion equipment; |
|
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|
our liquidity and the availability of external sources of financing; and |
|
|
|
the availability of more economically attractive prospects. |
There can be no assurance that the budgeted wells will, if drilled, encounter commercial
quantities of crude oil or natural gas.
Factors that could cause us to further increase our level of activity and capital budget in
2011 include an improvement in commodity prices or well performance that exceeds our risked
forecasts, the divestiture of non-strategic conventional assets, a reduction in service and
material costs, or the formation of joint ventures with other exploration and production companies
outside of our core de-risked acreage positions in the Williston Basin, all of which would
positively impact our operating cash flow.
Factors that would cause us to reduce our capital budget in 2011 include, but are not limited
to, reductions in commodity prices or underperformance of wells relative to our risked forecasts or
increases in service and materials costs, all of which would negatively impact our operating cash
flow.
Our budgeted oil and gas capital expenditures for 2011 are as follows:
|
|
|
|
|
|
|
2011 |
|
|
|
(In millions) |
|
Drilling |
|
$ |
582.1 |
|
Support infrastructure |
|
|
83.2 |
|
Land |
|
|
27.4 |
|
|
|
|
|
Total oil and gas capital expenditures |
|
$ |
692.7 |
|
|
|
|
|
To support our prospect generation activities, we allocate a portion of our capital
expenditures to land and seismic. Over the past three years, we have spent $162.9 million on land, excluding proceeds from asset sales, to expand our acreage position
primarily in the Williston Basin.
For a more in depth discussion of our 2010 and 2011 capital expenditures see Item 2.
Properties.
41
Contractual Obligations
The following schedule summarizes our known contractual cash obligations at December 31, 2010
and the effect these obligations are expected to have on our future cash flow and liquidity.
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|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013- |
|
|
2015 and |
|
|
|
Total |
|
|
2011 |
|
|
2012 |
|
|
2014 |
|
|
Thereafter |
|
|
|
(In thousands) |
|
Debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Notes |
|
$ |
300,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
300,000 |
|
Senior Credit Facility |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
300,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
300,000 |
|
Other commitments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest, Senior Notes(a) |
|
$ |
210,000 |
|
|
$ |
26,250 |
|
|
$ |
26,250 |
|
|
$ |
52,500 |
|
|
$ |
105,000 |
|
Interest, Senior Credit Facility(b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling rigs(c) |
|
|
42,582 |
|
|
|
9,432 |
|
|
|
10,785 |
|
|
|
21,900 |
|
|
|
465 |
|
Non-cancelable operating leases |
|
|
1,199 |
|
|
|
793 |
|
|
|
406 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
553,781 |
|
|
$ |
36,475 |
|
|
$ |
37,441 |
|
|
$ |
74,400 |
|
|
$ |
405,465 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Calculated assuming $300 million of Senior Notes outstanding and an interest rate of 8.75%.
The payments are made in April and October until maturity in October 2018. |
|
(b) |
|
Calculated assuming no amounts outstanding under our Senior Credit Facility. The interest
rate under our facility is dependent upon Eurodollar borrowing rates plus a margin that
fluctuates dependent upon the amount outstanding under the facility. The Eurodollar rate for
one month borrowings was 0.32% on December 31, 2010. The amount of interest that we pay on
amounts borrowed under our Senior Credit Facility will fluctuate over time as borrowings
increase or decrease, as the applicable Eurodollar rate increases and decreases and as the
applicable interest rate increases or decreases. See Item 7A. Quantitative and Qualitative
Disclosures About Market Risk Interest Rate Risk. |
|
(c) |
|
Contractual agreements with third-party service providers to
procure drilling rigs for exploratory and development activities.
See Item 8. Financial Statements and Supplementary Data Note 10 Contingencies, Commitments and Factors Which May Affect Future
Obligations. |
We also have liabilities of $5.9 million related to asset retirement obligations on our
Consolidated Balance Sheet as of December 31, 2010. Due to the nature of these obligations, we
cannot determine precisely when payments will be made to settle these obligations. See Item 8.
Financial Statements and Supplementary Data Note 7. Asset Retirement Obligations.
Crude Oil and Natural Gas Reserves
Our estimated total net proved reserves of crude oil and natural gas as of December 31, 2010,
2009 and 2008 were as follows.
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|
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|
At December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Estimated Net Proved Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (MMBbls) |
|
|
52.2 |
|
|
|
16.6 |
|
|
|
7.1 |
|
Natural gas (Bcf) |
|
|
87.8 |
|
|
|
66.4 |
|
|
|
94.7 |
|
Oil equivalent (MMBoe)(a) |
|
|
66.8 |
|
|
|
27.7 |
|
|
|
22.8 |
|
Proved developed reserves as a percentage of net proved reserves |
|
|
35 |
% |
|
|
37 |
% |
|
|
46 |
% |
|
|
|
(a) |
|
Boe is defined as one barrel of oil equivalent determined using the ratio of six Mcf of
natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
42
Our estimated total net proved reserves increased 141% from 2009 to 2010. The increase in our
year-end 2010 proved reserves is attributable to both the increased level of our drilling activity
and the continued application of advance drilling and completion techniques in the Williston Basin.
During 2010, we drilled and completed, were completing or were drilling 41.6 net wells versus 6.9 net wells in 2009. Our advanced techniques incorporate drilling long
lateral horizontal wellbores approximately 10,000 in length and completing wells with multi-stage
fracture stimulations ranging typically from 30 to 38 fracture stimulations, which has improved our
rates of return. During 2010, we implemented widespread application of our advanced drilling and
completion techniques in Mountrail, Williams and McKenzie Counties, North Dakota and drilled our
initial well in Roosevelt County, Montana and drilled economic wells. In the Williston Basin, our
reserves increased 260% to 55.4 MMBoe.
Partially offsetting our proved reserve increases, we eliminated multiple PUD reserve
locations in our onshore Gulf Coast province where we currently do not anticipate drilling the
locations within the next five years. The PUD reserve locations that we eliminated were primarily
natural gas drilling locations in our South Texas acreage positions and totaled 0.8 MMBoe.
Results of Operations
Comparison of the twelve-month periods ended December 31, 2010, 2009 and 2008
Production volumes
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|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
Crude oil (MBbls)(a) |
|
|
2,216 |
|
|
|
167 |
% |
|
|
830 |
|
|
|
44 |
% |
|
|
578 |
|
Natural gas (MMcf) |
|
|
4,562 |
|
|
|
(23 |
%) |
|
|
5,892 |
|
|
|
(26 |
%) |
|
|
7,996 |
|
Total (MBoe)(b) |
|
|
2,976 |
|
|
|
64 |
% |
|
|
1,812 |
|
|
|
(5 |
%) |
|
|
1,910 |
|
Average daily production volumes
(Boe/d)(c) |
|
|
8,267 |
|
|
|
64 |
% |
|
|
5,034 |
|
|
|
(5 |
%) |
|
|
5,306 |
|
|
|
|
(a) |
|
Includes approximately 29,654 and 16,475 barrels of oil produced in 2010 and 2009,
respectively, and added to inventory in the respective year. Ending inventory at year end 2008
and was not material. |
|
(b) |
|
Boe is defined as one barrel equivalent of crude oil, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
|
(c) |
|
Average daily production volumes calculated based on 360 day year. |
Increase in Inventory During the Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
Crude oil (Bbls) |
|
|
29,654 |
|
|
|
80 |
% |
|
|
16,475 |
|
|
NM |
|
|
|
|
|
Natural gas (Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Boe) |
|
|
29,654 |
|
|
|
80 |
% |
|
|
16,475 |
|
|
NM |
|
|
|
|
|
Sales volumes (Production volumes less increase in Inventory)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
Crude oil (MBbls)(a) |
|
|
2,186 |
|
|
|
169 |
% |
|
|
814 |
|
|
|
41 |
% |
|
|
578 |
|
Natural gas (MMcf) |
|
|
4,562 |
|
|
|
(23 |
%) |
|
|
5,892 |
|
|
|
(26 |
%) |
|
|
7,996 |
|
Total (MBoe)(b) |
|
|
2,947 |
|
|
|
64 |
% |
|
|
1,796 |
|
|
|
(6 |
%) |
|
|
1,910 |
|
Average daily sales volumes (Boepd)(c) |
|
|
8,185 |
|
|
|
64 |
% |
|
|
4,988 |
|
|
|
(6 |
%) |
|
|
5,306 |
|
|
|
|
(a) |
|
Excludes approximately 29,654 and 16,475 barrels of oil produced in 2010 and 2009,
respectively, and recorded as inventory at year-end. Ending inventory at year end 2008 was not
material. |
|
(b) |
|
Boe is defined as one barrel equivalent of crude oil, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
|
(c) |
|
Average daily sales volumes calculated based on 360 day year. |
43
Our net equivalent sales volumes for 2010 increased by 64% to 2,947 MBoe (8,185 Boepd) from
1,796 MBoe (4,988 Boepd) in 2009. Our sales volumes for 2010 increased primarily due to our
increased activity level in the Williston Basin, which drove crude oil sales volume growth of 169%
from 2009 to 2010. This increase was partially offset by a 23% decrease in our natural gas volumes
due to the natural decline of our wells. Crude oil as a percent of total production increased to
74% from 45% of our total production in 2010 and 2009, respectively, also as a result of our
increased level of drilling activity in the Williston Basin.
The following is additional information regarding our 2010 sales volumes:
|
|
|
Sales volumes from our Williston Basin province for 2010 increased 244% when compared
to 2009. The increase was attributable to the rapid acceleration of our drilling activities
in the Williston Basin. Sales volumes from this province represented 74% of our total sales
volumes in 2010 versus 35% in 2009. Approximately 93% of our 2010 sales volumes from this
province were oil compared to 96% in 2009. |
|
|
|
Sales volumes from our Onshore Gulf Coast province for 2010 decreased 36% when compared
to 2009. The decrease in volumes was attributable to the reduction in our drilling activity
in this province in order to focus our activities in the Williston Basin. Because of our
limited drilling program, only limited new volumes were brought on line to offset the
natural decline of our wells. Sales volumes from this province represented 17% of our total
sales volumes in 2010 versus 44% in 2009. Approximately 82% of our 2010 sales volumes from
this province were natural gas compared to 89% in 2009. |
|
|
|
Sales volumes from our Anadarko Basin province for 2010 decreased 23% when compared to
2009. The decrease in volumes was attributable to the reduction in drilling activity in
this province in order to focus our activities in the Williston Basin. Because of the
reduction in our drilling program in this province, limited new volumes were brought on
line to offset the natural decline of our wells. Sales volumes from this province
represented 7% of our volumes in 2010 versus 15% in 2009. Approximately 92% of our 2010
sales volumes from this province were natural gas compared to 92% in 2009. |
|
|
|
Sales volumes from our West Texas & Other province for 2010 decreased 45% when compared
to 2009. The decrease in volumes was attributable to the reduction in our drilling activity
in this province in order to focus our activities in the Williston Basin and the sale of
producing properties in the second quarter 2010. Because of our limited drilling program,
only limited new volumes were brought on line to offset the natural decline of our wells.
Sales volumes from this province represented 2% of our total volumes in 2010 versus 6% in
2009. Approximately 87% of our 2010 sales volumes from this province were oil compared to
89% in 2009. |
The following is additional information regarding our 2009 sales volumes.
|
|
|
Sales volumes from our Williston Basin province for 2009 increased 116% when compared
to 2008. The increase was attributable to the rapid escalation of our drilling activities
in the Williston Basin. Sales volumes from this province represented 35% of our total
volumes in 2009 versus 15% in 2008. Approximately 96% of our 2009 sales volumes from this
province were oil compared to 97% in 2008. |
|
|
|
Sales volumes from our Onshore Gulf Coast province for 2009 decreased 32% when compared
to 2008. The decrease in volumes was attributable to the reduction in our drilling activity
in this province in order to focus our activities in the Williston Basin. Because of our
limited drilling program, only limited new volumes were brought on line to offset the
natural decline of our wells. Sales volumes from this province represented 44% of our total
sales volumes in 2009 versus 61% in 2008. Approximately 89% of our 2009 sales volumes from
this province were natural gas compared to 87% in 2008. |
|
|
|
Sales volumes from our Anadarko Basin province for 2009 decreased 20% when compared to
2008. The decrease in volumes was attributable to the reduction in drilling activity in
this province in order to focus our activities in the Williston Basin. Because of the
reduction in our drilling program in this province, no new volumes were brought on line to
offset the natural decline of our wells. Sales volumes from this province represented 15%
of our volumes in 2009 versus 17% in 2008. Approximately 92% of our 2009 sales volumes from
this province were natural gas compared to 93% in 2008. |
|
|
|
Sales volumes from our West Texas & Other province for 2009 decreased 17% when compared
to 2008. The decrease in volumes was attributable to the reduction in our drilling activity
in this province in order to focus our activities in the Williston Basin. Because of our
limited drilling program, only limited new volumes were brought on line to offset the
natural decline of our wells. Sales volumes from this province represented 6% of our total
volumes in 2009 versus 7% in 2008. Approximately 88% of our 2009 sales volumes from this
province were oil compared to 88% in 2008. |
44
Revenue, commodity prices and hedging
The following table shows our revenue from the sale of crude oil and natural gas for 2010,
2009 and 2008. Our commodity hedges are accounted for using mark-to-market accounting, which
requires us to record both derivative settlements and unrealized derivative gains (losses) to the
consolidated statement of operations within a single income statement line item. We include both
derivative settlements and unrealized derivative gains (losses) within revenue.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
|
(In thousands, except per unit measurements) |
|
Crude oil revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil revenue |
|
$ |
155,403 |
|
|
|
249 |
% |
|
$ |
44,580 |
|
|
|
(13 |
%) |
|
$ |
51,449 |
|
Crude oil derivative settlement
gains (losses) |
|
|
(468 |
) |
|
|
(28 |
%) |
|
|
(654 |
) |
|
|
(74 |
%) |
|
|
(2,564 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil revenue including
derivative settlements |
|
$ |
154,935 |
|
|
|
253 |
% |
|
$ |
43,926 |
|
|
|
(10 |
%) |
|
$ |
48,885 |
|
Crude oil derivative unrealized
gains (losses) |
|
|
(13,808 |
) |
|
|
218 |
% |
|
|
(4,343 |
) |
|
NM |
|
|
|
2,983 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil revenue including
derivative settlements and
unrealized gains (losses) |
|
|
141,127 |
|
|
|
257 |
% |
|
|
39,583 |
|
|
|
(24 |
%) |
|
|
51,868 |
|
Natural gas revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue |
|
$ |
23,876 |
|
|
|
1 |
% |
|
$ |
23,612 |
|
|
|
(68 |
%) |
|
$ |
73,659 |
|
Natural gas derivative settlement
gains (losses) |
|
|
3,577 |
|
|
|
(64 |
%) |
|
|
10,031 |
|
|
NM |
|
|
|
(1,028 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue including
derivative settlements |
|
$ |
27,453 |
|
|
|
(18 |
%) |
|
$ |
33,643 |
|
|
|
(54 |
%) |
|
$ |
72,631 |
|
Natural gas derivative unrealized
gains (losses) |
|
|
633 |
|
|
NM |
|
|
|
(2,970 |
) |
|
NM |
|
|
|
3,157 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue including
derivative settlements and
unrealized gains (losses) |
|
|
28,086 |
|
|
|
(8 |
%) |
|
|
30,673 |
|
|
|
(60 |
%) |
|
|
75,788 |
|
Crude oil and natural gas revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas revenue |
|
$ |
179,279 |
|
|
|
163 |
% |
|
$ |
68,192 |
|
|
|
(45 |
%) |
|
$ |
125,108 |
|
Crude oil and natural gas
derivative settlement gains
(losses) |
|
|
3,109 |
|
|
|
(67 |
%) |
|
|
9,377 |
|
|
NM |
|
|
|
(3,592 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas
revenue including derivative
settlement gains (losses) |
|
|
182,388 |
|
|
|
135 |
% |
|
|
77,569 |
|
|
|
(36 |
%) |
|
|
121,516 |
|
Crude oil and natural gas
derivative unrealized gains
(losses) |
|
|
(13,175 |
) |
|
|
80 |
% |
|
|
(7,313 |
) |
|
NM |
|
|
|
6,140 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas
revenue including derivative
settlements and unrealized
gains (losses) |
|
|
169,213 |
|
|
|
141 |
% |
|
|
70,256 |
|
|
|
(45 |
%) |
|
|
127,656 |
|
Support infrastructure revenue |
|
|
489 |
|
|
NM |
|
|
|
|
|
|
NM |
|
|
|
|
|
Other revenue |
|
|
20 |
|
|
|
(77 |
%) |
|
|
88 |
|
|
|
(33 |
%) |
|
|
132 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue |
|
$ |
169,722 |
|
|
|
141 |
% |
|
$ |
70,344 |
|
|
|
(45 |
%) |
|
$ |
127,788 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average crude oil prices (based
on sales volumes): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil price (per Bbl) |
|
$ |
71.08 |
|
|
|
30 |
% |
|
$ |
54.79 |
|
|
|
(38 |
%) |
|
$ |
89.06 |
|
Crude oil price including
derivative settlement gains
(losses) (per Bbl) |
|
$ |
70.87 |
|
|
|
31 |
% |
|
$ |
53.99 |
|
|
|
(36 |
%) |
|
$ |
84.63 |
|
Crude oil price including
derivative settlements and
unrealized gains (losses) (per
Bbl) |
|
$ |
64.55 |
|
|
|
33 |
% |
|
$ |
48.65 |
|
|
|
(46 |
%) |
|
$ |
89.79 |
|
45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
|
(In thousands, except per unit measurements) |
|
Average natural gas prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price (per Mcf) |
|
$ |
5.23 |
|
|
|
30 |
% |
|
$ |
4.01 |
|
|
|
(56 |
%) |
|
$ |
9.21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price including
derivative settlement gains
(losses) (per Mcf) |
|
$ |
6.02 |
|
|
|
5 |
% |
|
$ |
5.71 |
|
|
|
(37 |
%) |
|
$ |
9.08 |
|
Natural gas price including
derivative settlements and
unrealized gains (losses) (per
Mcf) |
|
$ |
6.16 |
|
|
|
18 |
% |
|
$ |
5.21 |
|
|
|
(45 |
%) |
|
$ |
9.48 |
|
Average oil equivalent prices
(based on sales volumes): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil equivalent price (per Bbl) |
|
$ |
60.84 |
|
|
|
60 |
% |
|
$ |
37.97 |
|
|
|
(42 |
%) |
|
$ |
65.46 |
|
Oil equivalent price including
derivative settlement gains
(losses) (per bbl) |
|
$ |
61.90 |
|
|
|
43 |
% |
|
$ |
43.19 |
|
|
|
(32 |
%) |
|
$ |
63.60 |
|
Oil equivalent price including
derivative settlements and
unrealized gains (losses) (per
Bbl) |
|
$ |
57.43 |
|
|
|
47 |
% |
|
$ |
39.12 |
|
|
|
(41 |
%) |
|
$ |
66.84 |
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
to 2010 |
|
|
to 2009 |
|
Change in revenue from the sale of crude oil |
|
|
|
|
|
|
|
|
Price variance impact |
|
$ |
35,622 |
|
|
$ |
(27,885 |
) |
Sales volume variance impact |
|
|
75,201 |
|
|
|
21,016 |
|
Cash settlement of derivative hedging contracts |
|
|
186 |
|
|
|
1,910 |
|
Unrealized gains (losses) due to derivative hedging contracts |
|
|
(9,465 |
) |
|
|
(7,326 |
) |
|
|
|
|
|
|
|
Total change |
|
$ |
101,544 |
|
|
$ |
(12,285 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in revenue from the sale of natural gas |
|
|
|
|
|
|
|
|
Price variance impact |
|
$ |
5,581 |
|
|
$ |
(30,657 |
) |
Sales volume variance impact |
|
|
(5,317 |
) |
|
|
(19,390 |
) |
Cash settlement of derivative hedging contracts |
|
|
(6,454 |
) |
|
|
11,059 |
|
Unrealized gains (losses) due to derivative hedging contracts |
|
|
3,603 |
|
|
|
(6,127 |
) |
|
|
|
|
|
|
|
Total change |
|
$ |
(2,587 |
) |
|
$ |
(45,115 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in revenue from the sale of crude oil and natural gas |
|
|
|
|
|
|
|
|
Price variance impact |
|
$ |
41,203 |
|
|
$ |
(58,542 |
) |
Volume variance impact |
|
|
69,884 |
|
|
|
1,626 |
|
Cash settlement of derivative hedging contracts |
|
|
(6,268 |
) |
|
|
12,969 |
|
Unrealized gains (losses) due to derivative hedging contracts |
|
|
(5,862 |
) |
|
|
(13,453 |
) |
|
|
|
|
|
|
|
Total change |
|
$ |
98,957 |
|
|
$ |
(57,400 |
) |
|
|
|
|
|
|
|
Our 2010 crude oil and natural gas revenue including derivative settlements and unrealized
gains (losses) increased $99.0 million, or 141% when compared to 2009. The following were the
primary reasons for the increase in our revenue:
|
|
|
a 169% increase in our crude oil sales volumes, which was partially offset by a 23%
decrease in our natural gas sales volumes, increased revenue by $69.9 million; |
|
|
|
a 60% increase in the average crude oil equivalent price increased revenue by $41.2
million; |
|
|
|
a $3.1 million gain from the settlement of derivative contracts in 2010 versus a $9.4
million settlement gain in 2009 decreased revenue by $6.3 million; and |
|
|
|
a $13.2 million unrealized loss due to derivative hedging contracts in 2010 versus a
$7.3 million unrealized loss due to derivative hedging contracts in 2009 decreased revenue
by $5.9 million. |
46
Our 2009 crude oil and natural gas revenue including derivative settlements and unrealized
gains (losses) decreased $57.4 million, or 45% when compared to 2008. The following were the
primary reasons for the decrease in our revenue:
|
|
|
a 42% decrease in the average oil equivalent price decreased revenue by $58.5 million; |
|
|
|
a $7.3 million unrealized loss due to derivative hedging contracts in 2009 versus a
$6.1 million unrealized gain due to derivative hedging contracts in 2008 decreased revenue
by $13.5 million; |
|
|
|
an 41% increase in our crude oil sales volumes, which was partially offset by a 26%
decrease in our natural gas sales volumes, increased revenue by $1.6 million; and |
|
|
|
a $9.4 million gain from the settlement of derivative contracts in 2009 versus a $3.6
million settlement loss in 2008 increased revenue by $13.0 million. |
Support infrastructure. Revenue from support infrastructure comes from fees related to our
support infrastructure assets in North Dakota, including fees from oil, natural gas, waste water
and fresh water gathering lines. Our produced water disposal wells in our Ross and Rough Rider
project areas became operational early in the fourth quarter 2010 and late in the fourth quarter
2010, respectively.
Other revenue. Other revenue relates to fees that we charge third parties who use our gas
gathering systems to move their production from the wellhead to third party gas pipeline systems.
Other revenue for 2010 was $20,000 compared to $88,000 in 2009 and $132,000 in 2008. Costs related
to our gas gathering systems are recorded in lease operating expenses.
Hedging. We utilize costless collars, swaps, puts, and three way costless collars to (i)
reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce
commodity price risk and (iii) provide a base level of cash flow in order to assure we can execute
at least a portion of our capital spending plans. See Item 7A. Quantitative and Qualitative
Disclosures About Market Risk Derivative Instruments and Hedging Activities for a description
of our derivative contracts and our open derivative contracts.
47
The following table details derivative contracts that settled during 2010, 2009 and 2008 and
includes the type of derivative contract, the volume, the weighted average NYMEX reference price
for those volumes, and the associated gain /(loss) upon settlement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
Crude oil collars and three
way costless collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (Bbls) |
|
|
1,056,500 |
|
|
|
321 |
% |
|
|
251,000 |
|
|
|
38 |
% |
|
|
182,500 |
|
Average floor price (per Bbl) |
|
$ |
62.51 |
|
|
|
5 |
% |
|
$ |
59.43 |
|
|
|
(15 |
%) |
|
$ |
69.55 |
|
Average ceiling price (per Bbl) |
|
$ |
93.02 |
|
|
|
16 |
% |
|
$ |
80.12 |
|
|
|
(15 |
%) |
|
$ |
93.82 |
|
Gain /(loss) upon settlement
(in thousands) |
|
$ |
(468 |
) |
|
NM |
|
|
$ |
902 |
|
|
NM |
|
|
$ |
(2,564 |
) |
Crude oil swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (Bbls) |
|
|
|
|
|
|
(100 |
%) |
|
|
90,000 |
|
|
NM |
|
|
|
|
|
Average swap price
(per Bbl) |
|
$ |
|
|
|
|
(100 |
%) |
|
$ |
50.75 |
|
|
NM |
|
|
$ |
|
|
Gain /(loss) upon settlement
(in thousands) |
|
$ |
|
|
|
|
(100 |
%) |
|
$ |
(1,556 |
) |
|
NM |
|
|
$ |
|
|
Total crude oil gain / (loss)
upon settlement (in thousands) |
|
$ |
(468 |
) |
|
|
(100 |
%) |
|
$ |
(654 |
) |
|
|
(75 |
%) |
|
$ |
(2,564 |
) |
Natural gas collars and three
way costless collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu) |
|
|
2,730,000 |
|
|
|
39 |
% |
|
|
1,960,000 |
|
|
|
(60 |
%) |
|
|
4,850,000 |
|
Average floor price (per
MMbtu) |
|
$ |
5.79 |
|
|
|
(19 |
%) |
|
$ |
7.19 |
|
|
|
(6 |
%) |
|
$ |
7.65 |
|
Average ceiling price (per
MMbtu) |
|
$ |
7.36 |
|
|
|
(17 |
%) |
|
$ |
8.83 |
|
|
|
(18 |
%) |
|
$ |
10.75 |
|
Gain /(loss) upon settlement
(in thousands) |
|
$ |
3,577 |
|
|
|
(56 |
%) |
|
$ |
8,133 |
|
|
NM |
|
|
$ |
(1,028 |
) |
Natural gas swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu) |
|
|
|
|
|
|
(100 |
%) |
|
|
2,490,000 |
|
|
NM |
|
|
|
|
|
Average swap price
(per MMbtu) |
|
$ |
|
|
|
|
(100 |
%) |
|
$ |
4.359 |
|
|
NM |
|
|
$ |
|
|
Gain /(loss) upon settlement
(in thousands) |
|
$ |
|
|
|
|
(100 |
%) |
|
$ |
1,898 |
|
|
NM |
|
|
$ |
|
|
Total natural gas gain /(loss)
upon settlement (in
thousands) |
|
$ |
3,577 |
|
|
|
(64 |
%) |
|
$ |
10,031 |
|
|
NM |
|
|
$ |
(1,028 |
) |
48
Operating costs and expenses
Production costs. We believe that per unit of production measures are the most effective basis
for evaluating our production costs. We use this information to internally evaluate our
performance, as well as to evaluate our performance relative to our peers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit-of-Production |
|
|
|
(Per Boe based on Sales Volumes) |
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
Production costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating & maintenance |
|
$ |
4.65 |
|
|
|
(23 |
%) |
|
$ |
6.02 |
|
|
|
22 |
% |
|
$ |
4.92 |
|
Expensed workovers |
|
|
1.38 |
|
|
|
(13 |
%) |
|
|
1.58 |
|
|
|
65 |
% |
|
|
0.96 |
|
Ad valorem taxes |
|
|
0.30 |
|
|
|
(46 |
%) |
|
|
0.56 |
|
|
|
(7 |
%) |
|
|
0.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
6.33 |
|
|
|
(22 |
%) |
|
$ |
8.16 |
|
|
|
26 |
% |
|
$ |
6.48 |
|
Production taxes |
|
|
5.88 |
|
|
|
107 |
% |
|
|
2.84 |
|
|
|
1 |
% |
|
|
2.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs |
|
$ |
12.21 |
|
|
|
11 |
% |
|
$ |
11.00 |
|
|
|
18 |
% |
|
$ |
9.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount |
|
|
|
(In thousands) |
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
Production costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating & maintenance |
|
$ |
13,698 |
|
|
|
27 |
% |
|
$ |
10,823 |
|
|
|
15 |
% |
|
$ |
9,399 |
|
Expensed workovers |
|
|
4,055 |
|
|
|
43 |
% |
|
|
2,832 |
|
|
|
53 |
% |
|
|
1,851 |
|
Ad valorem taxes |
|
|
898 |
|
|
|
(10 |
%) |
|
|
1,000 |
|
|
|
(10 |
%) |
|
|
1,113 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
18,651 |
|
|
|
27 |
% |
|
$ |
14,655 |
|
|
|
19 |
% |
|
$ |
12,363 |
|
Production taxes |
|
|
17,313 |
|
|
|
240 |
% |
|
|
5,098 |
|
|
|
(5 |
%) |
|
|
5,374 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs |
|
$ |
35,964 |
|
|
|
82 |
% |
|
$ |
19,753 |
|
|
|
11 |
% |
|
$ |
17,737 |
|
For 2010, our per unit production cost increased 11% when compared to 2009. The following were
the primary reasons for the increase in our 2010 per unit production costs relative to 2009:
|
|
|
production taxes increased 107% due to higher commodity sales prices and higher crude
oil sales volumes in North Dakota, which are subject to an 11.5% tax rate; and |
|
|
|
higher production taxes were partially offset by 23% lower per unit lease operating
expense, which was attributable to 64% higher sales volumes in 2010 as compared to that in
2009. |
For 2009, our per unit production cost increased 18% when compared to 2008. The following were
the primary reasons for the increase in our 2009 per unit production costs relative to 2008:
|
|
|
O&M expenses increased 22%, or by $1.10 per Boe, due to increases in salt water
disposal, compressor rental and overhead fees; and |
|
|
|
expensed workovers increased 65%, or by $0.62 per Boe, due to an increase in the number
and cost of our workovers in 2009, in particular two workovers associated with our
conventional natural gas wells. |
Support infrastructure. We incur costs to operate our support infrastructure assets in North
Dakota. Our produced water disposal wells in our Ross and Rough Rider project areas became
operational early in the fourth quarter 2010 and late in the fourth quarter 2010, respectively.
49
General and administrative expenses. We capitalize a portion of our general and administrative
costs. Capitalized costs include the cost of technical employees who work directly on our prospect
generation and exploration activities and a portion of our associated technical organization costs
such as supervision, telephone and postage.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
|
(In thousands, except per unit measurements which are based on sales volumes) |
|
General and
administrative
costs |
|
$ |
25,495 |
|
|
|
50 |
% |
|
$ |
16,961 |
|
|
|
(3 |
%) |
|
$ |
17,551 |
|
Capitalized general
and administrative
costs |
|
|
(12,552 |
) |
|
|
63 |
% |
|
|
(7,718 |
) |
|
|
(4 |
%) |
|
|
(7,994 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and
administrative
Expenses |
|
$ |
12,943 |
|
|
|
40 |
% |
|
$ |
9,243 |
|
|
|
(3 |
%) |
|
$ |
9,557 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and
administrative
expenses (per Boe) |
|
$ |
4.39 |
|
|
|
(15 |
%) |
|
$ |
5.15 |
|
|
|
3 |
% |
|
$ |
4.98 |
|
Our general and administrative expenses in 2010 increased $3.7 million from those in 2009.
Before capitalization, our general and administrative costs increased by $8.5 million. The
following were the primary reasons for the increase in our 2010 general and administrative costs
relative to 2009:
|
|
|
total compensation expense increased by $7.9 million due to the reinstatement of full
salaries in late 2009 due to improved economic conditions, the reinstatement of our bonus
plan in 2010, higher levels of employee salaries in 2010 to ensure competitive compensation
levels with other oil and gas companies, and a higher number of employees due to our
increased activity level in the Williston Basin; and |
|
|
|
other office expense increased by $0.6 million due to higher information technology
costs. |
Our general and administrative expenses in 2009 decreased $0.3 million from those in 2008.
Before capitalization, our general and administrative costs decreased by $0.6 million. The
following were the primary reasons for the decrease in general and administrative costs:
|
|
|
total compensation expense decreased by $0.3 million from 2008 to 2009 due to lower
levels of employee salaries and bonuses associated with our cost cutting measures
implemented in April 2009; and |
|
|
|
office expenses decreased by $0.3 million from 2008 to 2009 due to our cost containment
measures. |
Depletion of crude oil and natural gas properties. Our full-cost depletion expense is driven
by many factors including certain costs spent in the exploration for and development of crude oil
and gas reserves, production levels, and estimates of proved reserve quantities and future
developmental costs at the end of the year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
|
(In thousands, except per unit measurements which are based on sales volumes) |
|
Depletion of crude
oil and natural gas
properties |
|
$ |
58,195 |
|
|
|
82 |
% |
|
$ |
32,054 |
|
|
|
(40 |
%) |
|
$ |
53,498 |
|
Depletion of crude
oil and natural gas
properties (per
Boe) |
|
$ |
19.75 |
|
|
|
11 |
% |
|
$ |
17.85 |
|
|
|
(36 |
%) |
|
$ |
28.02 |
|
Our depletion expense for 2010 was $26.1 million higher than 2009. An increase in production
volumes in 2010 increased depletion expense by approximately $20.5 million and our higher depletion
rate increased depletion expense $5.6 million.
Our depletion expense for 2009 was $21.4 million lower than 2008. A decrease in production
volumes in 2009 lowered depletion expense by approximately $3.2 million, while a decrease in our
depletion rate decreased depletion expense $18.2 million. The lower depletion rate was due to our
fourth quarter 2008 and first quarter 2009 ceiling test writedowns.
50
Impairment of crude oil and natural gas properties. We use the full cost method of accounting
for crude oil and gas properties. Under this method, all acquisition, exploration and development
costs, including certain payroll, asset retirement costs, other internal costs, and interest
incurred for the purpose of finding crude oil and natural gas reserves, are capitalized. Internal
costs and interest capitalized are directly attributable to acquisition, exploration and
development activities and do not include costs related to production, general corporate overhead
or similar activities.
Capitalized costs of crude oil and natural gas properties, net of accumulated amortization,
are limited to the present value (10% per annum discount rate) of estimated future net cash flow
from proved crude oil and natural gas reserves, based on the average of crude oil and natural gas
prices in effect at the beginning of each month in the twelve month period prior to the end of the
reporting period; plus the cost of properties not being amortized, if any; plus the lower of cost
or estimated fair value of unproved properties included in the costs being amortized, if any; less
related income tax effects. If net capitalized costs of crude oil and gas properties exceed this
ceiling amount, we are subject to a ceiling test writedown to the extent of such excess. A ceiling
test writedown is a non-cash charge to earnings and reduces stockholders equity in the period of
occurrence.
The risk that we will experience a ceiling test writedown increases when crude oil and gas
prices are depressed or if we have a substantial downward revisions in our estimated proved
reserves. Prior to December 31, 2009, the ceiling test calculation was based on crude oil and
natural gas prices in effect on the balance sheet date. Based on crude oil and gas prices in effect
on March 31, 2009 ($3.63 per MMBtu for Henry Hub gas and $49.65 per barrel for West Texas
Intermediate crude oil, adjusted for differentials), the unamortized cost of our crude oil and gas
properties exceeded the ceiling limit and we recorded a $114.8 million impairment to our crude oil
and gas properties. Based on crude oil and gas prices in effect on December 31, 2008 ($5.71 per
MMBtu for Henry Hub gas and $44.60 per barrel for West Texas Intermediate crude oil, adjusted for
differentials), the unamortized cost of our crude oil and gas properties exceeded the ceiling limit
and we recorded a $237.2 million impairment to our crude oil and gas properties.
Inventory Valuation. Our $2.2 million inventory valuation loss in 2009 was attributable to the
lower of cost or market writedown of oil country tubular goods (OCTG). Market prices of OCTG
experienced a substantial reduction in the first quarter of 2009 associated with lower steel costs
and the oversupply of OCTG due to reduced drilling activity in the United States.
Net interest expense. Interest on our Senior Notes, our Senior Credit Facility and dividends
that we paid on our Series A mandatorily redeemable preferred stock represents the largest portion
of our interest expense. Other costs include commitment fees that we pay on the unused portion of
the borrowing base for our Senior Credit Facility. In addition, we typically pay loan and debt
issuance costs when we enter into new lending agreements or amend existing agreements. When
incurred, these costs are recorded as non-current assets and are then amortized over the life of
the loan. We capitalize interest costs on borrowings associated with our major capital projects
prior to their completion. Capitalized interest is added to the cost of the underlying assets and
is amortized over the lives of the assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
|
(In thousands) |
|
Interest on Senior Notes |
|
$ |
18,240 |
|
|
|
18 |
% |
|
$ |
15,400 |
|
|
|
0 |
% |
|
$ |
15,401 |
|
Interest on Senior Credit Facility |
|
|
26 |
|
|
|
(99 |
%) |
|
|
3,375 |
|
|
|
72 |
% |
|
|
1,960 |
|
Commitment fees |
|
|
636 |
|
|
|
226 |
% |
|
|
195 |
|
|
|
(24 |
%) |
|
|
256 |
|
Dividend on mandatorily
redeemable preferred stock |
|
|
269 |
|
|
|
(56 |
%) |
|
|
606 |
|
|
|
0 |
% |
|
|
608 |
|
Amortization of deferred loan and
debt issuance cost |
|
|
1,939 |
|
|
|
26 |
% |
|
|
1,538 |
|
|
|
49 |
% |
|
|
1,032 |
|
Other general interest expense |
|
|
108 |
|
|
|
260 |
% |
|
|
30 |
|
|
NM |
|
|
|
|
|
Capitalized interest expense |
|
|
(9,770 |
) |
|
|
107 |
% |
|
|
(4,713 |
) |
|
|
(1 |
%) |
|
|
(4,762 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense |
|
$ |
11,448 |
|
|
|
(30 |
%) |
|
$ |
16,431 |
|
|
|
13 |
% |
|
$ |
14,495 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average debt outstanding |
|
$ |
201,447 |
|
|
|
(27 |
%) |
|
$ |
274,211 |
|
|
|
25 |
% |
|
$ |
220,116 |
|
Average interest rate on
outstanding indebtedness(a) |
|
|
9.57 |
% |
|
|
|
|
|
|
7.15 |
% |
|
|
|
|
|
|
8.28 |
% |
|
|
|
(a) |
|
Calculated as the sum of the interest on our outstanding indebtedness, commitment fees
that we pay on our unused borrowing capacity and the dividend on our mandatorily redeemable
preferred stock divided by the weighted average debt and preferred stock outstanding for the
period. |
51
Our net interest expense for 2010 was $5.0 million lower than that in 2009 primarily due to a
$5.1 million increase in capitalized interest expense associated with our higher level of activity
in the Williston Basin. Interest expense also decreased $3.3 million due to lower levels of debt
outstanding on our Senior Credit Facility subsequent to its repayment in October 2009 in
conjunction with our common stock offering. These decreases were partially offset by a $2.8
million increase in interest expense associate with the September 2010 issuance of our $300 million
Senior Notes due 2018.
Our net interest expense for 2009 was $1.9 million higher than that in 2008 primarily due to a
$1.4 million increase in interest expense associated with higher levels of outstanding debt on our
Senior Credit Facility and a $0.5 million increase in origination fees also associated with our
Senior Credit Facility.
Loss on early redemption of Senior Notes. In September 2010, we issued $300 million in Senior
Notes due 2018 which funded the tender offer for and redemption of our 9 5/8% Senior Notes due in
2014. As a result of the redemption process, we incurred a loss on the Senior Notes due in 2014.
Other income (expense). Other income (expense) included:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
|
(In thousands) |
|
Other: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on sale of inventory or assets |
|
|
831 |
|
|
|
105 |
% |
|
|
405 |
|
|
NM |
|
|
|
|
|
Other income (loss) |
|
|
4,263 |
|
|
|
274 |
% |
|
|
1,139 |
|
|
|
115 |
% |
|
|
530 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (loss) |
|
$ |
5,094 |
|
|
|
230 |
% |
|
$ |
1,544 |
|
|
|
191 |
% |
|
$ |
530 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income increased in 2010
as a result of higher levels of field general equipment
income in the Williston Basin, which was driven by accelerated development in the basin.
Income taxes. We utilize the asset and liability approach to measure deferred tax assets and
liabilities based on temporary differences existing at each balance sheet date using currently
enacted tax rates in accordance with Financial Accounting Standards Board Accounting Standards
Codification Topic 740 Income Taxes (FASB ASC 740). Under FASB ASC 740, deferred tax assets are
reduced by a valuation allowance when, in the opinion of management, it is more likely than not
that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and
liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.
In 2010, we recognized a current year net deferred tax expense of $1.1 million. The $1.1
million in tax expense was mainly attributable to the state of North Dakotas deferred tax expense.
The primary reasons for the difference between our effective tax rate of 2.5% and the federal
statutory rate of 35% were decreases in our valuation allowances on federal and state net operating
losses and our inability to deduct dividends and certain portions of our non-cash stock
compensation expense for federal tax purposes.
In 2009, we recognized a current year net deferred tax benefit of $233,000. The $233,000 tax
benefit was mainly due to miscellaneous state tax benefits. The primary reasons for the difference
between our effective tax rate of 0.2% and the federal statutory rate of 35% were increases in our
valuation allowances on federal and state net operating losses and our inability to deduct
dividends and certain portions of our non-cash stock compensation expense for federal tax purposes.
In 2008, we recognized a current year net deferred federal tax benefit of $40.8 million. The
$40.8 million tax benefit was due to a $222 million decrease in pre-tax income, which primarily
resulted from the ceiling test writedown of $237.2 million. We also recognized a current year net
deferred state tax benefit of $2 million, which consisted of the Margin Tax and other state tax
benefits. The primary reasons for the difference between our
effective tax rate of 20.8% and the federal statutory rate of 35% were increases in our
valuation allowances on federal and state net operating losses and our inability to deduct
dividends and certain portions of our non-cash stock compensation expense for federal tax purposes.
52
Liquidity and Capital Resources
Sources of Capital
In 2011, we intend to fund our capital expenditure program and contractual commitments with
cash, cash equivalents and short term investments on hand as of year-end 2010, cash flows from
operations, reimbursements of prior land and seismic costs by third parties who participate in our
projects, the potential sale of interests in projects and properties, availability under our Senior
Credit Facility or alternative financing sources.
Senior Notes
As of December 31, 2010, we had outstanding $300 million of 8 3/4% Senior Notes due 2018,
which were issued in September 2010. In connection with the issuance of the 8 3/4% Senior Notes,
we tendered for and purchased or redeemed $160 million of our 9 5/8% Senior Notes due 2014 in
September and October 2010.
Our 8 3/4% Senior Notes are fully and unconditionally guaranteed by us, and our wholly-owned
subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. Beginning April 2011, we will pay 8 3/4%
interest on the $300 million outstanding. Future interest payments are due semi-annually in
arrears in October and April of each year.
The 8 3/4% Senior Notes are our unsecured senior obligations, and:
|
|
|
rank equally in right of payment with all our existing and future senior indebtedness; |
|
|
|
rank senior to all of our future subordinated indebtedness; and |
|
|
|
are effectively junior in right of payment to all of our and our guarantors existing
and future secured indebtedness, including debt of our Senior Credit Facility. |
The Indenture governing the 8 3/4% Senior Notes contains customary events of default. Upon
the occurrence of certain events of default, the trustee or the holders of the 8 3/4% Senior Notes
may declare all outstanding 8 3/4% Senior Notes to be due and payable immediately.
Additionally, the Indenture governing the 8 3/4% Senior Notes contains customary restrictions
and covenants which could potentially limit our flexibility to manage and fund our business. We
were in compliance with all covenants associated with the 8 3/4% Senior Notes as of December 31,
2010.
Senior Credit Facility
As of December 31, 2010, our Senior Credit Facility provided for revolving credit borrowings
up to $200 million and had a borrowing base of $110 million. Subsequent to December 31, 2010, we
entered into our Fifth Amended and Restated Credit Facility in February 2011, which provides for
revolving credit borrowings up to $600 million, a current borrowing base of $325 million and a five
year maturity. As of December 31, 2010 and as of the date of the filing of this report, we had no
amounts outstanding under our Senior Credit Facility.
The borrowing base under the new Senior Credit Facility will be redetermined at least
semi-annually and the amount of borrowing capacity available to us under the new Senior Credit
Facility could fluctuate. In the event that the borrowing base is adjusted below the amount that we
have borrowed, our access to further borrowings will be reduced, and we may not have the resources
necessary to pay off the borrowing base deficiency and carry out our planned spending for
exploration and development activities. See Item 1A Risk Factors Availability under our
Senior Credit Facility is based on a borrowing base which is subject to redetermination by our
lenders. If our borrowing base is reduced, we may be required to repay amounts outstanding under
our Senior Credit Facility.
53
Borrowings under our new Senior Credit Facility bear interest at a base rate or a Eurodollar
rate, at our election, plus in each case an applicable margin. These margins are reset quarterly
and are subject to increase if the total
amount borrowed under our new Senior Credit Facility reaches certain percentages of the
available borrowing base, as shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent of |
|
Eurodollar |
|
|
|
|
|
|
|
Borrowing Base |
|
Rate |
|
|
Base Rate |
|
|
Commitment |
|
Utilized |
|
Advances |
|
|
Advances(1) |
|
|
Fee |
|
< 50% |
|
|
2.00 |
% |
|
|
1.00 |
% |
|
|
0.50 |
% |
≥ 50% |
|
|
2.25 |
% |
|
|
1.25 |
% |
|
|
0.50 |
% |
≥ 75% |
|
|
2.50 |
% |
|
|
1.50 |
% |
|
|
0.50 |
% |
≥ 90% |
|
|
2.75 |
% |
|
|
1.75 |
% |
|
|
0.50 |
% |
|
|
|
(1) |
|
Base Rate means for any day a fluctuating rate per annum equal to the highest of the
following: (a) the Federal Funds Rate plus 1/2 of 1%, (b) the Eurodollar Rate with respect
to Interest Periods of one month determined as of approximately 11:00 a.m. (London time) on
such day plus 1.00% and (c) the rate of interest in effect for such day as publicly
announced from time to time by Bank of America as its prime rate. The prime rate is a
rate set by Bank of America based upon various factors including Bank of Americas costs
and desired return, general economic conditions and other factors, and is used as a
reference point for pricing some loans, which may be priced at, above, or below such
announced rate. Any change in such rate announced by Bank of America shall take effect at
the opening of business on the day specified in the public announcement of such change. |
Our new Senior Credit Facility also contains customary restrictions and covenants. Should we
be unable to comply with these or other covenants, our senior lenders may be unwilling to waive
compliance or amend the covenants and our liquidity may be adversely affected. Pursuant to our
Senior Credit Facility, our current ratio must be at least 1.0 to 1 and net leverage ratio must not
be greater than 4.00 to 1.
Mandatorily Redeemable Preferred Stock
In June 2010, we exercised our option to redeem all of our Series A mandatorily redeemable
preferred stock at 101% of the stated value per share, which was held by DLJ Merchant Banking
Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse
Securities (USA), LLC.
Off Balance Sheet Arrangements
We currently have operating leases, which are considered off balance sheet arrangements. We
do not currently have any other off balance sheet arrangements or other such unrecorded
obligations, and we have not guaranteed the debt of any other party.
Analysis of Changes In Cash and Cash Equivalents
The table below summarizes our sources and uses of cash during 2010, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
|
(In thousands) |
|
Net income |
|
$ |
42,896 |
|
|
NM |
|
|
$ |
(122,992 |
) |
|
|
24 |
% |
|
$ |
(162,247 |
) |
Non-cash charges |
|
|
90,735 |
|
|
|
(43 |
%) |
|
|
159,132 |
|
|
|
(35 |
%) |
|
|
245,545 |
|
Changes in working capital and other
items |
|
|
10,889 |
|
|
|
(30 |
%) |
|
|
15,610 |
|
|
NM |
|
|
|
(13,668 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows provided by operating
activities |
|
$ |
144,520 |
|
|
|
179 |
% |
|
$ |
51,750 |
|
|
|
(26 |
%) |
|
$ |
69,630 |
|
Cash flows used by investing activities |
|
|
(556,211 |
) |
|
|
238 |
% |
|
|
(164,620 |
) |
|
|
(8 |
%) |
|
|
(179,866 |
) |
Cash flows provided (used) by
financing activities |
|
|
394,653 |
|
|
|
247 |
% |
|
|
113,608 |
|
|
|
(17 |
%) |
|
|
136,416 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and
cash equivalents |
|
$ |
(17,038 |
) |
|
NM |
|
|
$ |
738 |
|
|
|
(97 |
%) |
|
$ |
26,180 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
Analysis of net cash provided by operating activities
Net cash provided by operating activities for 2010 was $92.8 million higher than 2009. The
following are the primary reasons for the increase:
|
|
|
higher crude oil volumes, which were partially offset by lower natural gas volumes,
increased operating cash flow by $69.9 million; |
|
|
|
higher oil equivalent sales prices increased operating cash flow by $41.2 million; |
|
|
|
higher production taxes decreased operating cash flow by $12.2 million; |
|
|
|
lower realized hedge settlements decreased operating cash flow by $6.3 million; |
|
|
|
the change in working capital decreased operating cash flow by $4.7 million; |
|
|
|
higher lease operating costs decreased operating cash flow by $4.0 million; and |
|
|
|
higher general and administrative expense reduced operating cash flow by $3.7 million. |
Net cash provided by operating activities for 2009 was $17.9 million lower than 2008. The
following are the primary reasons for the decrease:
|
|
|
a 42% decrease in sales prices of crude oil and natural gas decreased operating cash
flow by $58.5 million; |
|
|
|
higher lease operating costs decreased operating cash flow by $2.3 million; |
|
|
|
the change in working capital increased operating cash flow by $29.3 million; |
|
|
|
higher realized hedge settlements increased operating cash flow by $13.0 million; and |
|
|
|
higher crude oil volumes partially offset by lower natural gas volumes decreased
revenue by $1.6 million. |
Working Capital
Working capital is the amount by which current assets exceed current liabilities. At the end
of 2010, as a result of our April 2010 equity offering and our September 2010 Senior Notes offering
we had both cash on hand and short term investments recorded on our balance sheet. This resulted in
a working capital surplus at the end of 2010. At year-end 2009, we also had a working capital
surplus as a result of our May and October 2009 equity offerings. At year-end 2008, we also had a
working capital surplus as we had fully drawn our credit facility and placed the associated cash on
deposit.
Our working capital surplus at December 31, 2010, December 31, 2009 and December 31, 2008 was
$184.3 million, $90.7 million and $30.3 million, respectively. Our working capital surplus at
December 31, 2010 and December 31, 2009 included a current asset of $224.0 million and $80.1
million, respectively, related to short term investments.
Analysis of changes in cash flows used by investing activities
Net cash used by investing activities increased by $391.6 million from 2009 to 2010. The
primary driver for the increase was a $375.0 million increase in capital expenditures for crude oil
and natural gas activities due to higher levels of drilling activity, lease acquisition, and
support infrastructure in the Williston Basin. Net cash used in investing activities also
increased $63.8 million due to the change in short term investments and $12.8 million due to the
change in inventory. These increases were partially offset by a $49.9 million decrease in cash
used associated with our increase in accrued drilling costs and $17.7 million in asset sale
proceeds which also decreased cash used during the period.
Net cash used by investing activities decreased by $15.2 million from 2008 to 2009. The
primary drivers for the decrease were a $78.0 million decrease in our drilling capital expenditures
and a $34.0 million decrease in our land and seismic capital expenditures. These decreases were
offset by a $80.1 million increase in cash used associated with our increased level of short term
investments and a $9.2 million increase in cash used associated with the change in our accrued
drilling costs.
55
The following is a detailed breakout of our net cash used in investing activities for 2010,
2009 and 2008 in thousands.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
% Change |
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
Capital expenditures for crude oil and
natural gas activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
$ |
280,080 |
|
|
|
381 |
% |
|
$ |
58,209 |
|
|
|
(57 |
%) |
|
$ |
136,248 |
|
Support infrastructure (a) |
|
|
33,226 |
|
|
NM |
|
|
|
|
|
|
|
0 |
% |
|
|
|
|
Land |
|
|
112,153 |
|
|
|
6,269 |
% |
|
|
1,761 |
|
|
|
(95 |
%) |
|
|
35,796 |
|
Capitalized cost |
|
|
21,470 |
|
|
|
73 |
% |
|
|
12,432 |
|
|
|
(3 |
%) |
|
|
12,852 |
|
Capitalized asset retirement obligation |
|
|
814 |
|
|
|
149 |
% |
|
|
327 |
|
|
|
(21 |
%) |
|
|
412 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
447,743 |
|
|
|
516 |
% |
|
$ |
72,729 |
|
|
|
(61 |
%) |
|
$ |
185,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciling Items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset sale proceeds including ARO
reduction liability |
|
$ |
(17,698 |
) |
|
NM |
|
|
$ |
|
|
|
|
0 |
% |
|
$ |
|
|
Change in short term investments |
|
|
143,898 |
|
|
|
80 |
% |
|
|
80,093 |
|
|
NM |
|
|
|
|
|
Change in other property and equipment
(b) |
|
|
6,235 |
|
|
|
280 |
% |
|
|
1,642 |
|
|
|
249 |
% |
|
|
470 |
|
Change in accrued drilling costs |
|
|
(45,569 |
) |
|
NM |
|
|
|
4,270 |
|
|
NM |
|
|
|
(4,927 |
) |
Change in drilling advances paid |
|
|
794 |
|
|
NM |
|
|
|
|
|
|
|
0 |
% |
|
|
|
|
Change in inventory |
|
|
20,709 |
|
|
|
163 |
% |
|
|
7,881 |
|
|
NM |
|
|
|
|
|
Other |
|
|
99 |
|
|
|
NM |
|
|
|
(1,995 |
) |
|
|
103 |
% |
|
|
(985 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Reconciling Items |
|
|
108,468 |
|
|
|
18 |
% |
|
|
91,891 |
|
|
NM |
|
|
|
(5,442 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
$ |
556,211 |
|
|
|
238 |
% |
|
$ |
164,620 |
|
|
|
(8 |
%) |
|
$ |
179,866 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Support infrastructure costs are recorded on our balance sheet in Other Property and
Equipment. |
|
(b) |
|
Excludes approximately $33.2 million in support infrastructure costs, which are
included in capital expenditures for crude oil and natural gas activities above. |
Analysis of changes in cash flows from financing activities
Over the three year period ended December 31, 2010, we have entered into various financing
transactions with the intent of increasing our liquidity so that we could fund our capital
expenditures for the exploration and development of crude oil and natural gas properties.
Our net cash provided by financing activities in 2010 was $281.0 million higher than in 2009.
In 2010, we received net proceeds of $277.5 million from our April common stock offering and net
proceeds of $118 million from our September 8 3/4% Senior Notes offering after both tendering for
and redeeming our 9 5/8 Senior Notes due 2014.
Our net cash provided by financing activities in 2009 was $22.8 million lower than in 2008. In
2009, we raised $261.7 million in net proceeds from the sale of common stock and repaid the $145.0
million outstanding under our Senior Credit Facility thereby generating net cash provided by
financing activities of $113.6 million. In 2008, we generated $135 million in financing proceeds
via borrowings under our Senior Credit Facility.
Common Stock Transactions
Our net proceeds from the sale of common stock and employee stock option exercises were $18.5
million higher in 2010 than they were in 2009 due to our April 2010 equity offering. This compares
to net proceeds that were $260.9 million higher in 2009 than in 2008 due to our May and October
2009 equity offerings.
The following is a list of common stock transactions that occurred in 2010, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
Shares Issued |
|
|
Net Proceeds |
|
|
|
|
|
|
(in thousands) |
|
2010 common stock transactions: |
|
|
|
|
|
|
|
|
April 2010 common stock offering |
|
|
16,100,000 |
|
|
$ |
277,547 |
|
Exercise of employee stock options |
|
|
741,037 |
|
|
$ |
3,884 |
|
2009 common stock transactions: |
|
|
|
|
|
|
|
|
May 2009 common stock offering |
|
|
36,292,117 |
|
|
$ |
93,407 |
|
October 2009 common stock offering |
|
|
16,837,523 |
|
|
$ |
168,318 |
|
Exercise of employee stock options |
|
|
256,314 |
|
|
$ |
1,219 |
|
2008 common stock transactions: |
|
|
|
|
|
|
|
|
Exercise of employee stock options |
|
|
385,715 |
|
|
$ |
2,066 |
|
56
Critical Accounting Policies
The establishment and consistent application of accounting policies is a vital component of
accurately and fairly presenting our consolidated financial statements in accordance with generally
accepted accounting principles (GAAP), as well as ensuring compliance with applicable laws and
regulations governing financial reporting. While there are rarely alternative methods or rules from
which to select in establishing accounting and financial reporting policies, proper application
often involves significant judgment regarding a given set of facts and circumstances and a complex
series of decisions.
Use of Estimates
The preparation of financial statements in accordance with GAAP in the United States of
America requires us to make estimates and assumptions that affect our reported assets, liabilities,
revenues, expenses, and some narrative disclosures. Our estimates of our proved crude oil and
natural gas reserves, future development costs, production expense, revenue and deferred income
taxes are the most critical to our financial statements.
Crude oil and Natural Gas Reserves
The determination of depreciation, depletion and amortization expense as well as impairments
that are recognized on our crude oil and natural gas properties are highly dependent on the
estimates of the proved crude oil and natural gas reserves attributable to our properties. Our
estimate of proved reserves is based on the quantities of crude oil and natural gas which
geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the
future years from known reservoirs under existing economic and operating conditions. The accuracy
of any reserve estimate is a function of the quality of available data, engineering and geological
interpretation, and judgment. For example, we must estimate the amount and timing of future
operating costs, severance taxes and development costs, all of which may in fact vary considerably
from actual results. In addition, as the prices of crude oil and natural gas and cost levels change
from year to year, the economics of producing our reserves may change and therefore the estimate of
proved reserves may also change. Any significant variance in these assumptions could materially
affect the estimated quantity and value of our reserves.
The information regarding present value of the future net cash flows attributable to our
proved crude oil and natural gas reserves are estimates only and should not be construed as the
current market value of the estimated crude oil and natural gas reserves attributable to our
properties. Thus, such information includes revisions of certain reserve estimates attributable to
our properties included in the prior years estimates. These revisions reflect additional
information from subsequent activities, production history of the properties involved and any
adjustments in the projected economic life of such properties resulting from changes in crude oil
and natural gas prices. Any future downward revisions could adversely affect our financial
condition, our borrowing ability, our future prospects and the value of our common stock.
The estimates of our proved crude oil and natural gas reserves used in the preparation of our
consolidated financial statements were prepared by CGA, our registered independent petroleum
consultants, and were prepared in accordance with the rules promulgated by the SEC.
Crude Oil and Natural Gas Property
The method of accounting we use to account for our crude oil and natural gas investments
determines what costs are capitalized and how these costs are ultimately matched with revenues and
expensed.
We utilize the full cost method of accounting to account for our crude oil and natural gas
investments instead of the successful efforts method because we believe it more accurately reflects
the underlying economics of our programs to explore and develop crude oil and natural gas reserves.
The full cost method embraces the concept that dry holes and other expenditures that fail to add
reserves are intrinsic to the oil and natural gas exploration business. Thus, under the full cost
method, all costs incurred in connection with the acquisition, development and exploration of crude
oil and natural gas reserves are capitalized. These capitalized amounts include the costs of
unproved properties, internal costs directly related to acquisitions, development and exploration
activities, asset retirement costs, geological and geophysical costs and capitalized interest.
Although some of these costs will ultimately result in no additional reserves, they are part of a
program from which we expect the benefits of successful wells to more than offset the costs of any
unsuccessful ones. The full cost method differs from the successful efforts method of accounting
for crude oil and natural gas investments. The primary difference between these two methods is the
treatment of exploratory dry hole costs. These costs are generally expensed under the
successful efforts method when it is determined that measurable reserves do not exist. Geological
and geophysical costs are also expensed under the successful efforts method. Under the full cost
method, both dry hole costs and geological and geophysical costs are initially capitalized and
classified as unevaluated properties pending determination of proved reserves. If no proved
reserves are discovered, these costs are then amortized with all the costs in the full cost pool.
57
Capitalized amounts except unevaluated costs are depleted using the units of production
method. The depletion expense per unit of production is the ratio of the sum of our unamortized
historical costs and estimated future development costs to our proved reserve volumes. Estimation
of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely
determined. Subsequent reserve estimates materially different from those reported would change the
depletion expense recognized during the future reporting periods. For the quarter ended December
31, 2010, our average depletion expense per unit of production was $18.64 per Boe. A 10% decrease
in our estimated net proved reserves at December 31, 2010 would result in a $2.04 per Boe
increase in our per unit depletion expense and a $3.5 million decrease in our pre-tax net income.
To the extent the capitalized costs in our full cost pool (net of depreciation, depletion and
amortization and related deferred taxes) exceed the sum of the present value (using a 10% discount
rate and based on period-end crude oil and natural gas prices) of the estimated future net cash
flows from our proved crude oil and natural gas reserves and the capitalized cost associated with
our unproved properties, we would have a capitalized ceiling impairment. Such costs would be
charged to operations as a reduction of the carrying value of crude oil and natural gas properties.
The risk that we will be required to write down the carrying value of our crude oil and natural gas
properties increases when crude oil and natural gas prices are depressed, even if the low prices
are temporary. In addition, capitalized ceiling impairment charges may occur if we experience poor
drilling results or estimations of our proved reserves are substantially reduced. A capitalized
ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact
operating income and stockholders equity. Once recognized, a capitalized ceiling impairment charge
to crude oil and natural gas properties cannot be reversed at a later date. The risk that we will
experience a ceiling test writedown increases when crude oil and gas prices are depressed or if we
have substantial downward revisions in our estimated proved reserves.
Based on crude oil and gas prices in effect on March 31, 2009 ($3.63 per MMBtu for Henry Hub
gas and $49.65 per barrel for West Texas Intermediate crude oil, adjusted for differentials), the
unamortized cost of our crude oil and gas properties exceeded the ceiling limit and we recorded a
$114.8 million ($71.9 million after tax) impairment to our crude oil and gas properties. Also, at
December 31, 2008, the unamortized cost of our crude oil and gas properties exceeded the ceiling
limit based on crude oil and gas prices in effect ($5.71 per MMBtu for Henry Hub gas and $44.60 per
barrel for West Texas Intermediate crude oil, adjusted for differentials). Therefore, we recorded a
$237.2 million ($148.6 million after tax) impairment to our crude oil and gas properties at
December 31, 2008.
No assurance can be given that we will not experience a capitalized ceiling impairment charge
in future periods. In addition, capitalized ceiling impairment charges may occur if estimates of
proved hydrocarbon reserves are substantially reduced or estimates of future development costs
increase significantly. See Item 1A. Risk Factors Exploratory drilling is a speculative
activity that may not result in commercially productive reserves and may require expenditures in
excess of budgeted amounts, Item 1A. Risk Factors We need to replace our reserves at a faster
rate than companies whose reserves have longer production lives. Our failure to replace our
reserves would result in decreasing reserves and production over time and Item 1A. Risk Factors
Lower crude oil and natural gas prices may cause us to record ceiling limitation writedowns,
which would reduce our stockholders equity. Additionally, the modernization of SEC oil and gas
reporting rules eliminated the ability to use subsequent pricing in assessing the need for a
ceiling limitation writedown. This could cause us to record a ceiling limitation writedown that
would not be required if subsequent pricing were used.
Asset Retirement Obligations
We have significant obligations to plug and abandon our crude oil and natural gas wells and
related equipment. Liabilities for asset retirement obligations are recorded at fair value in the
period incurred. The related asset value is increased by the same amount. Asset retirement costs
included in the carrying amount of the related asset are subsequently allocated to expense as part
of our depletion calculation. See - Crude oil and Natural Gas Property. Additionally, increases
in the discounted asset retirement liability resulting from the passage of time are reported as
accretion of discount on asset retirement obligations expense on our Consolidated Statement of
Operations.
Estimating future asset retirement obligations requires us to make estimates and judgments
regarding timing, existence of a liability, as well as what constitutes adequate restoration. We
use the present value of estimated cash flows related to our asset retirement obligations to
determine the fair value. Present value calculations inherently
incorporate numerous assumptions and judgments, which include the ultimate retirement and
restoration costs, inflation factors, credit adjusted discount rates, timing of settlement, and
changes in the legal, regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the present value of our existing asset retirement obligation
liability, a corresponding adjustment will be made to the carrying cost of the related asset.
58
Income Taxes
Deferred tax assets are recognized for temporary differences in financial statement and tax
basis amounts that will result in deductible amounts and carry-forwards in future years. Deferred
tax liabilities are recognized for temporary differences that will result in taxable amounts in
future years. Deferred tax assets and liabilities are measured using enacted tax law and tax
rate(s) for the year in which we expect the temporary differences to be deducted or settled. The
effect of a change in tax law or rates on the valuation of deferred tax assets and liabilities is
recognized in income in the period of enactment. Deferred tax assets are reduced by a valuation
allowance when, in the opinion of management, it is more likely than not that some portion or all
of the deferred tax assets will not be realized. Significant future taxable income would be
required to realize this net deferred tax asset.
Estimating the amount of the valuation allowance is dependent on estimates of future taxable
income, alternative minimum taxable income, and changes in stockholder ownership that would trigger
limits on use of net operating losses under Internal Revenue Code Section 382.
We have a significant net deferred tax asset associated with net operating loss carryforwards
(NOLs). Based on estimates of the reversal of our temporary differences, it is more likely than not that we will not use all of these NOLs to offset current tax
liabilities in future years. We have, therefore, established a valuation allowance on the portion
of the NOLs that may expire unused. Our NOLs are more fully described in Item 8. Financial Statements and Supplementary Data Note
8. Income Taxes.
Revenue Recognition
We derive revenue primarily from the sale of the crude oil and natural gas that we produce,
hence our revenue recognition policy for these sales is significant.
We recognize revenue from the sale of crude oil using the sales method of accounting. Under
this method, we recognize revenue when we deliver crude oil and title transfers.
We recognize revenue from the sale of natural gas using the entitlements method of accounting.
Under this method, we recognize revenue based on our entitled ownership percentage of sales of
natural gas delivered to purchasers. Gas imbalances occur when we sell more or less than our
entitled ownership percentage of total natural gas production. When we receive less than our
entitled share, a receivable is recorded. When we receive more than our entitled share, a liability
is recorded.
Settlements for hydrocarbon sales can occur up to two months after the end of the month in
which the crude oil, natural gas or other hydrocarbon products were produced. We estimate and
accrue for the value of these sales using information available to us at the time our financial
statements are generated. Differences are reflected in the accounting period that payments are
received from the purchaser.
Derivative Instruments and Hedging Activities
We use derivative instruments to manage our market risks associated with fluctuations in crude
oil and natural gas prices. We enter into derivative contracts, including costless collars, swaps,
ceilings and floors, which upon settlement require payments to (or receipts from) counterparties
based on the difference between a fixed price and a variable price for fixed quantities of crude
oil and natural gas without exchanging underlying volumes. The notional amounts of these financial
instruments are based on expected production from existing and future wells.
All derivatives are accounted for in accordance with FASB ASC 815 and carried at fair value on
the balance sheet. We utilize the mark-to-market methodology to account for our hedges.
Mark-to-market accounting requires
that both derivative settlements and unrealized gains (losses) are recorded on the
consolidated statement of operations. We have elected to include all derivative settlement and
unrealized gains (losses) within revenues.
59
New Accounting Pronouncements
On December 31, 2008, the SEC published the final rules and interpretations updating its oil
and gas reporting requirements. Many of the revisions are updates to definitions in the existing
oil and gas rules to make them consistent with the petroleum resource management system, which is a
widely accepted standard for the management of petroleum resources that was developed by several
industry organizations. Key revisions include the ability to include nontraditional resources in
reserves, the use of new technology for determining reserves, permitting disclosure of probable and
possible reserves, and changes to the pricing used to determine reserves in that companies must use
a 12-month average price. The average is calculated using the first-day-of-the-month price for each
of the 12 months that make up the reporting period. The SEC required companies to comply with the
amended disclosure requirements for registration statements filed after January 1, 2010, and for
annual reports for fiscal years ending on or after December 15, 2009. Early adoption was not
permitted. Financial Accounting Standards Board Accounting Standards Codification Topic 932
Extractive Activities Oil and Gas (FASB ASC 932) provides guidance for oil and natural gas
reserve related disclosures in the financial statements. Adoption of the new requirements did not
have a material impact on Brighams financial statements.
Other Matters
Commodity Prices
Changes in commodity prices significantly affect our capital resources, liquidity and
operating results. Price changes directly affect revenues and can indirectly impact expected
production by changing the amount of capital available we have to reinvest in our exploration and
development activities. Commodity prices are impacted by many factors that are outside of our
control. Over the past few of years, commodity prices have been highly volatile. We expect that
commodity prices will continue to fluctuate significantly in the future. As a result, we cannot
accurately predict future crude oil and natural gas prices, and therefore, we cannot determine what
effect increases or decreases will have on our capital program, production volumes and future
revenues.
The prices we receive for our crude oil production are based on global market conditions. Our
average pre-hedged sales price for crude oil in 2010 was $71.08 per barrel, which was 30% higher
than the prices we received in 2009. Significant factors that will impact 2011 crude oil prices
include the pace at which the domestic and global economies continue to recover, the extent to
which members of the Organization of Petroleum Exporting Countries and other crude oil exporting
nations are able to manage crude oil supply through export quotas and geopolitical developments in
African and Middle East Countries.
Natural gas prices are primarily driven by North American market forces. However, global LNG
shipments can impact North American markets to the extent cargoes are diverted from Asia or Europe
to North America. Factors that can affect the price of natural gas are changes in market demands,
overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis
differentials and other factors. Over the past three years, natural gas prices have been volatile.
Our average pre-hedged sales price for natural gas in 2010 was $5.23 per Mcf, which was 30% higher
than the price we received in 2009. Natural gas prices in 2011 will be dependent upon many factors
including the balance between North American supply and demand.
Derivative Instruments
Our results of operations and operating cash flow are impacted by changes in market prices for
crude oil and gas. We believe the use of derivative instruments, although not free of risk, allows
us to reduce our exposure to crude oil and natural gas sales price fluctuations and thereby achieve
a more predictable cash flow. While the use of derivative instruments limits the downside risk of
adverse price movements, their use may also limit future revenues from favorable price movements.
Moreover, our derivative contracts generally do not apply to all of our production and thus provide
only partial price protection against declines in commodity prices. We expect that the amount of
our derivative contracts will vary from time to time. See Item 1A. Risk Factors Our hedging
activities may prevent us from benefiting from price increases and may expose us to other risks
and Item 7A. Quantitative and Qualitative Disclosures About Market Risk Derivative Instruments
and Hedging Activities.
60
Effects of Inflation and Changes in Prices
Our results of operations and cash flows are affected by changing crude oil and natural gas
prices. If the price of crude oil and natural gas increases (decreases), there could be a
corresponding increase (decrease) in revenues as well as the operating costs that we are required
to bear for operations.
Environmental and Other Regulatory Matters
Our business is subject to certain federal, state and local laws and regulations relating to
the exploration for and the development, production and marketing of crude oil and natural gas, as
well as environmental and safety matters. Many of these laws and regulations have become more
stringent in recent years, often imposing greater liability on a larger number of potentially
responsible parties. Although we believe that we are in substantial compliance with all applicable
laws and regulations, the requirements imposed by laws and regulations are frequently changed and
subject to interpretation, and we cannot predict the ultimate cost of compliance with these
requirements or their effect on our operations. Any suspensions, terminations or inability to meet
applicable bonding requirements could materially adversely affect our financial condition and
operations. Although significant expenditures may be required to comply with governmental laws and
regulations applicable to us, compliance has not had a material adverse effect on our earnings or
competitive position. Future regulations may add to the cost of, or significantly limit, drilling
activity. See Item 1A. Risk Factors We are subject to various governmental regulations and
environmental risks that may cause us to incur substantial costs and Item 1. Business
Governmental Regulation and Item 1. Business Environmental Matters.
|
|
|
Item 7A. |
|
Quantitative and Qualitative Disclosures About Market Risk |
Management Opinion Concerning Derivative Instruments
We use derivative instruments to manage exposure to commodity prices. Our objectives for
holding derivatives are to achieve a relatively consistent level of cash flow to support a portion
of our planned capital spending. Our use of derivative instruments for hedging activities could
materially affect our results of operations in particular quarterly or annual periods since such
instruments can limit our ability to benefit from favorable price movements. We do not enter into
derivative instruments for trading purposes.
Fair Value of Derivative Contracts
We use the mark-to-market accounting methodology to account for our hedges. At the end of each
quarter, our derivatives are marked-to-market to reflect the current fair value and both derivative
settlements and unrealized gains (losses) are recorded on the consolidated statement of operations.
We include all derivative settlements and unrealized gains (losses) within revenue.
The fair values of our derivative contracts are determined based on counterparties estimates
and valuation models. We did not change our valuation methodology during the year ended December
31, 2010. The following table reconciles the changes that occurred in the fair values of our open
derivative contracts during 2010.
|
|
|
|
|
|
|
Fair Value of |
|
|
|
Undesignated |
|
|
|
Derivative |
|
|
|
Contracts |
|
Estimated fair value of open contracts at December 31, 2009 |
|
$ |
(1,975 |
) |
|
|
|
|
Changes in fair values of derivative contracts: |
|
|
|
|
Natural gas collars |
|
$ |
4,210 |
|
Crude oil collars |
|
|
(14,276 |
) |
Settlements of derivative contracts that were open at December 31, 2009: |
|
|
|
|
Natural gas collars |
|
$ |
(3,578 |
) |
Crude oil collars |
|
|
468 |
|
|
|
|
|
Estimated fair value of open contracts at December 31, 2010 |
|
$ |
(15,151 |
) |
|
|
|
|
61
Derivative Instruments and Hedging Activities
Our primary commodity market risk exposure is to changes in the prices that we receive for our
crude oil and natural gas production. The market prices for crude oil and natural gas have been
highly volatile and are likely to continue to be highly volatile in the future. As such, we employ
established policies and procedures to manage our exposure to fluctuations in the sales prices we
receive for our crude oil and natural gas production via using derivative instruments.
While the use of derivative instruments limits the downside risk of adverse price movements,
their use may also limit future revenues from favorable price movements. Moreover, our derivative
contracts generally do not apply to all of our production and thus provide only partial price
protection against declines in commodity prices. We expect that the amount of our derivative
contracts will vary from time to time.
During 2010, we were party to crude oil costless collars, crude oil swaps, crude oil puts,
natural gas costless collars, natural gas three-way costless collars, and natural gas swaps. See
Item 8. Financial Statements and Supplementary Data Note 11. Derivative Instruments and Hedging
Activities for additional information regarding our derivative contracts.
We use costless collars to establish floor (purchased put option) and ceiling prices (written
call option) on our anticipated future crude oil and natural gas production. We neither receive nor
pay net premiums when we enter into these option arrangements. These contracts are settled monthly.
When the settlement price for a period is above the ceiling price (written call option), we pay our
counterparty. When the settlement price for a period is below the floor price (purchased put
option), our counterparty is required to pay us. All hedges are accounted for using mark-to-market
accounting.
A three-way costless collar consists of a costless collar (purchased put option and written
call option) plus a put (written put) sold by us with a price below the floor price (purchased put
option) of the costless collar. We neither receive nor pay net premiums when we enter into these
option arrangements. These contracts are settled monthly. The written put requires us to make a
payment to our counterparty if the settlement price for a period is below the written put price.
Combining the costless collar (purchased put option and written call option) with the written put
results in us being entitled to a net payment equal to the difference between the floor price
(purchased put option) of the costless collar and the written put price if the settlement price is
equal to or less than the written put price. If the settlement price is greater than the written
put price, the result is the same as it would have been with a costless collar. This strategy
enables us to increase the floor and the ceiling price of the collar beyond the range of a
traditional costless collar while offsetting the associated cost with the sale of the written put.
All hedges are accounted for using mark-to-market accounting.
We also use put options to establish floor prices (purchased put option) on our anticipated
future crude oil production. We pay an initial premium when we enter into these option
arrangements. These contracts are settled monthly. When the settlement price for a period is
below the floor price (purchased put option), our counterparty is required to pay us. All hedges
are accounted for using mark-to-market accounting.
We use swaps to fix the sales price for our anticipated future natural gas production. Upon
settlement, we receive a fixed price for the hedged commodity and pay our counterparty a floating
market price, as defined in each instrument. These instruments are settled monthly. When the
floating price exceeds the fixed price for a contract month, we pay our counterparty. When the
fixed price exceeds the floating price, our counterparty is required to make a payment to us. All
hedges are accounted for using mark-to-market accounting.
Natural gas derivative transactions are generally settled based upon the average reported
settlement prices on the NYMEX for the last three trading days of a particular contract month.
Crude oil derivative transactions are generally settled based on the average reported settlement
prices on the NYMEX for each trading day of a particular calendar month.
62
The following table reflects our open derivative contracts at December 31, 2010, the
associated volumes and the corresponding weighted average NYMEX reference price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude |
|
|
Purchased |
|
|
Written |
|
|
|
Oil |
|
|
Put |
|
|
Call |
|
Settlement Period |
|
(Bbls) |
|
|
(Nymex) |
|
|
(Nymex) |
|
Crude Oil Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
01/01/11 12/31/11 |
|
|
84,000 |
|
|
$ |
65.00 |
|
|
$ |
88.25 |
|
01/01/11 12/31/11 |
|
|
60,000 |
|
|
$ |
60.00 |
|
|
$ |
97.25 |
|
01/01/11 12/31/11 |
|
|
60,000 |
|
|
$ |
65.00 |
|
|
$ |
108.00 |
|
01/01/11 06/30/11 |
|
|
18,000 |
|
|
$ |
65.00 |
|
|
$ |
97.50 |
|
01/01/11 12/31/11 |
|
|
48,000 |
|
|
$ |
70.00 |
|
|
$ |
106.80 |
|
01/01/11 12/31/11 |
|
|
48,000 |
|
|
$ |
75.00 |
|
|
$ |
102.60 |
|
07/01/11 12/31/11 |
|
|
12,000 |
|
|
$ |
75.00 |
|
|
$ |
103.00 |
|
01/01/11 06/30/11 |
|
|
24,000 |
|
|
$ |
70.00 |
|
|
$ |
92.50 |
|
07/01/11 09/30/11 |
|
|
9,000 |
|
|
$ |
70.00 |
|
|
$ |
95.00 |
|
10/01/11 12/31/11 |
|
|
6,000 |
|
|
$ |
70.00 |
|
|
$ |
96.35 |
|
01/01/11 02/28/11 |
|
|
10,000 |
|
|
$ |
70.00 |
|
|
$ |
92.00 |
|
01/01/11 07/31/11 |
|
|
21,000 |
|
|
$ |
70.00 |
|
|
$ |
94.80 |
|
01/01/11 03/31/11 |
|
|
9,000 |
|
|
$ |
75.00 |
|
|
$ |
93.50 |
|
07/01/11 12/31/11 |
|
|
12,000 |
|
|
$ |
75.00 |
|
|
$ |
95.15 |
|
01/01/11 12/31/11 |
|
|
36,000 |
|
|
$ |
75.00 |
|
|
$ |
104.30 |
|
01/01/12 06/30/12 |
|
|
60,000 |
|
|
$ |
75.00 |
|
|
$ |
106.90 |
|
01/01/11 02/28/11 |
|
|
8,000 |
|
|
$ |
75.00 |
|
|
$ |
103.50 |
|
03/01/11 04/30/11 |
|
|
16,000 |
|
|
$ |
75.00 |
|
|
$ |
104.50 |
|
01/01/11 12/31/11 |
|
|
36,000 |
|
|
$ |
65.00 |
|
|
$ |
100.00 |
|
01/01/11 07/31/12 |
|
|
289,000 |
|
|
$ |
65.00 |
|
|
$ |
97.20 |
|
01/01/11 07/31/12 |
|
|
289,000 |
|
|
$ |
65.00 |
|
|
$ |
98.55 |
|
01/01/11 07/31/12 |
|
|
289,000 |
|
|
$ |
65.00 |
|
|
$ |
100.00 |
|
01/01/11 07/31/12 |
|
|
289,000 |
|
|
$ |
65.00 |
|
|
$ |
100.40 |
|
03/01/11 08/31/11 |
|
|
46,000 |
|
|
$ |
65.00 |
|
|
$ |
94.80 |
|
09/01/11 12/31/11 |
|
|
61,000 |
|
|
$ |
65.00 |
|
|
$ |
97.40 |
|
01/01/12 06/30/12 |
|
|
182,000 |
|
|
$ |
65.00 |
|
|
$ |
99.25 |
|
09/01/11 12/31/11 |
|
|
61,000 |
|
|
$ |
65.00 |
|
|
$ |
99.00 |
|
03/01/11 08/31/11 |
|
|
46,000 |
|
|
$ |
65.00 |
|
|
$ |
96.75 |
|
01/01/12 06/30/12 |
|
|
91,000 |
|
|
$ |
65.00 |
|
|
$ |
101.00 |
|
01/01/12 06/30/12 |
|
|
182,000 |
|
|
$ |
65.00 |
|
|
$ |
100.75 |
|
01/01/12 06/30/12 |
|
|
91,000 |
|
|
$ |
65.00 |
|
|
$ |
102.75 |
|
07/01/12 07/31/12 |
|
|
62,000 |
|
|
$ |
65.00 |
|
|
$ |
102.25 |
|
05/01/11 12/31/11 |
|
|
122,500 |
|
|
$ |
65.00 |
|
|
$ |
100.00 |
|
07/01/12 07/31/12 |
|
|
31,000 |
|
|
$ |
65.00 |
|
|
$ |
105.25 |
|
05/01/11 12/31/11 |
|
|
122,500 |
|
|
$ |
65.00 |
|
|
$ |
106.50 |
|
01/01/11 02/28/11 |
|
|
29,500 |
|
|
$ |
65.00 |
|
|
$ |
98.75 |
|
01/01/11 12/31/11 |
|
|
182,500 |
|
|
$ |
65.00 |
|
|
$ |
100.00 |
|
01/01/12 06/30/12 |
|
|
136,500 |
|
|
$ |
65.00 |
|
|
$ |
107.25 |
|
07/01/12 09/30/12 |
|
|
92,000 |
|
|
$ |
65.00 |
|
|
$ |
109.40 |
|
08/01/12 09/30/12 |
|
|
61,000 |
|
|
$ |
65.00 |
|
|
$ |
110.25 |
|
08/01/12 09/30/12 |
|
|
61,000 |
|
|
$ |
65.00 |
|
|
$ |
112.00 |
|
10/01/12 10/31/12 |
|
|
62,000 |
|
|
$ |
65.00 |
|
|
$ |
112.65 |
|
01/01/12 07/31/12 |
|
|
106,500 |
|
|
$ |
65.00 |
|
|
$ |
110.00 |
|
01/01/11 06/30/11* |
|
|
90,500 |
|
|
$ |
65.00 |
|
|
$ |
95.00 |
|
01/01/11 06/30/11* |
|
|
90,500 |
|
|
$ |
65.00 |
|
|
$ |
97.50 |
|
08/01/12 10/31/12 |
|
|
92,000 |
|
|
$ |
70.00 |
|
|
$ |
110.90 |
|
10/01/12 10/31/12 |
|
|
31,000 |
|
|
$ |
70.00 |
|
|
$ |
110.90 |
|
08/01/12 10/31/12 |
|
|
92,000 |
|
|
$ |
70.00 |
|
|
$ |
106.50 |
|
11/01/12 12/31/12 |
|
|
122,000 |
|
|
$ |
70.00 |
|
|
$ |
107.70 |
|
11/01/12 12/31/12 |
|
|
122,000 |
|
|
$ |
70.00 |
|
|
$ |
110.00 |
|
|
|
|
* |
|
Crude oil collar was completed in two phases. First, the put option (floor) was purchased.
Subsequently, the call option (ceiling) was sold thereby converting the position into a collar. |
63
|
|
|
|
|
|
|
|
|
|
|
Crude |
|
|
Purchased |
|
|
|
Oil |
|
|
Put |
|
Settlement Period |
|
(Bbls) |
|
|
(Nymex) |
|
Crude Oil Floors |
|
|
|
|
|
|
|
|
01/01/12 06/30/12 |
|
|
91,000 |
|
|
$ |
65.00 |
|
01/01/12 06/30/12 |
|
|
91,000 |
|
|
$ |
65.00 |
|
01/01/12 06/30/12 |
|
|
45,500 |
|
|
$ |
65.00 |
|
01/01/12 06/30/12 |
|
|
45,500 |
|
|
$ |
65.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
Purchased |
|
|
Written |
|
|
|
Gas |
|
|
Put |
|
|
Call |
|
Settlement Period |
|
(MMbtu) |
|
|
(Nymex) |
|
|
(Nymex) |
|
Natural Gas Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
01/01/11 03/31/11 |
|
|
120,000 |
|
|
$ |
6.50 |
|
|
$ |
8.25 |
|
01/01/11 03/31/11 |
|
|
210,000 |
|
|
$ |
6.40 |
|
|
$ |
7.80 |
|
01/01/11 12/31/11 |
|
|
360,000 |
|
|
$ |
5.75 |
|
|
$ |
7.65 |
|
01/01/11 12/31/11 |
|
|
480,000 |
|
|
$ |
5.75 |
|
|
$ |
7.40 |
|
04/01/11 12/31/11 |
|
|
360,000 |
|
|
$ |
5.00 |
|
|
$ |
6.55 |
|
The following table reflects commodity derivative contracts entered into subsequent to
December 31, 2010, the associated volumes and the corresponding weighted average NYMEX reference
price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude |
|
|
Purchased |
|
|
Written |
|
|
|
Oil |
|
|
Put |
|
|
Call |
|
Settlement Period |
|
(Bbls) |
|
|
(Nymex) |
|
|
(Nymex) |
|
Crude oil Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
07/01/11 12/31/11** |
|
|
276,000 |
|
|
$ |
65.00 |
|
|
$ |
100.00 |
|
08/01/12 10/31/12 |
|
|
276,000 |
|
|
$ |
75.00 |
|
|
$ |
112.50 |
|
11/01/12 12/31/12 |
|
|
244,000 |
|
|
$ |
75.00 |
|
|
$ |
112.50 |
|
07/01/12 07/31/12 |
|
|
62,000 |
|
|
$ |
75.00 |
|
|
$ |
114.00 |
|
01/01/13 02/28/13 |
|
|
118,000 |
|
|
$ |
75.00 |
|
|
$ |
113.05 |
|
01/01/13 03/31/13 |
|
|
180,000 |
|
|
$ |
80.00 |
|
|
$ |
120.00 |
|
03/01/13 03/31/13 |
|
|
62,000 |
|
|
$ |
80.00 |
|
|
$ |
120.00 |
|
|
|
|
|
|
|
|
|
|
|
|
Crude |
|
|
Purchased |
|
|
|
Oil |
|
|
Put |
|
Settlement Period |
|
(Bbls) |
|
|
(Nymex) |
|
Crude Oil Floors |
|
|
|
|
|
|
|
|
07/01/12 12/31/12 |
|
|
276,000 |
|
|
$ |
80.00 |
|
|
|
|
** |
|
Crude oil collar was completed in two phases. First, the put option (floor) was purchased prior
to December 31, 2010. Subsequently, the call option (ceiling) was sold in January 2011 thereby
converting the position into a collar. |
Interest Rate Risk
At December 31, 2010, we had $300 million of long term debt, all of which was fixed rate. Our
fixed rate long-term debt consists entirely of our $300 million 8 3/4% Senior Notes due 2018.
The interest rate that we pay on amounts borrowed under our Senior Credit Facility is derived
from the Eurodollar rate and a margin that is applied to the Eurodollar rate. This calculation was
performed using the one month Eurodollar rate on December 31, 2010, which was 0.32%. The margin
that we pay is based upon the percentage of our available borrowing base that we utilize at the
beginning of the quarter. At December 31, 2010, the borrowing base for our Senior Credit Facility
was $110 million. Since we had no outstanding balance under our Senior Credit Facility at December
31, 2010, we were utilizing 0% of our available borrowing base. At this level of utilization, our
Senior Credit Facility requires us to pay a margin of 2.50%. Our all-in interest rate that we would
be
required to pay on the amounts borrowed under our Senior Credit Facility would have been
2.82%. A 10% increase in the Eurodollar rate would equal approximately three basis points. Such an
increase in the Eurodollar rate would change our annual interest expense by approximately $33,000,
assuming amounts borrowed under our Senior Credit Facility equaled our total potential borrowing
base of $110 million as of December 31, 2010. At year-end 2010, we had no amounts outstanding
under our Senior Credit Facility.
64
|
|
|
Item 8. |
|
Financial Statements and Supplementary Data |
Our Consolidated Financial Statements required by this item are included on the pages
immediately following the Index to Financial Statements appearing on page F-1.
|
|
|
Item 9. |
|
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
|
|
|
Item 9A. |
|
Controls and Procedures |
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2010, our management, including our principal executive officer and
principal financial officer, has evaluated the effectiveness of the design and operation of our
disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of
1934. There are inherent limitations to the effectiveness of any system of disclosure controls and
procedures, including the possibility of human error and the circumvention or overriding of the
controls and procedures. Accordingly, even effective disclosure controls and procedures can only
provide reasonable assurance of achieving their control objectives. Based upon and as of the date
of the evaluation, our principal executive officer and our principal financial officer concluded
that the design and operation of our disclosure controls and procedures were effective at a
reasonable assurance level in that they ensure that information required to be disclosed by us in
the reports that we file or submit under the Securities and Exchange Act of 1934 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 Chief Executive Officer and
Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Managements Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). 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. Under the supervision and
with the participation of our management, including our principal executive officer and principal
financial officer, we conducted an evaluation of the effectiveness of our internal control over
financial reporting based on the framework in Internal Control Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our
evaluation under the framework in Internal Control Integrated Framework issued by the COSO, our
management concluded that our internal control over financial reporting was effective as of
December 31, 2010.
The effectiveness of our internal control over financial reporting as of December 31, 2010 has
been audited by KPMG LLP, an independent registered public accounting firm, as stated in their
report, which is included herein.
Changes in Internal Control over Financial Reporting
There has been no change in our internal control over financial reporting during the fourth
quarter of 2010 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
|
|
|
Item 9B. |
|
Other Information |
None.
65
PART III
|
|
|
Item 10. |
|
Directors, Executive Officers and Corporate Governance |
The information required by this item is incorporated by reference to the 2011 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2010.
Pursuant to Item 401(b) of Regulation S-K, the information required by this item with respect
to our executive officers is set forth in Part I of this report.
|
|
|
Item 11. |
|
Executive Compensation |
The information required by this item is incorporated herein by reference to the 2011 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2010.
|
|
|
Item 12. |
|
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters |
The information required by this item is incorporated herein by reference to the 2011 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2010. See Item 5. Market for Registrants Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities, which sets forth certain
information with respect to our equity compensation plans.
|
|
|
Item 13. |
|
Certain Relationships and Related Transactions, and Director Independence |
The information required by this item is incorporated herein by reference to the 2011 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2010.
|
|
|
Item 14. |
|
Principal Accounting Fees and Services |
The information required by this item is incorporated herein by reference to the 2011 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2010.
PART IV
|
|
|
Item 15. |
|
Exhibits, Financial Statement Schedules |
|
(a) |
|
1. Consolidated Financial Statements: See Index to Financial Statements on page F-1. |
|
2. |
|
No schedules are required. |
The exhibits listed in the accompanying Index to Exhibits are filed or incorporated by
reference as part of the annual report.
66
GLOSSARY OF OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used in the oil and
gas industry and in this report. The definitions of proved developed reserves, proved reserves and
proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule
4-10(a)(2-4) of Regulation S-X.
3-D seismic. The method by which a three dimensional image of the earths subsurface is
created through the interpretation of reflection seismic data collected over surface grid. 3-D
seismic surveys allow for a more detailed understanding of the subsurface than do conventional
surveys and contribute significantly to field appraisal, development and production.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to
crude oil or other liquid hydrocarbons.
Boe. A barrel of oil equivalent is approximately six thousand cubic feet of typical natural
gas.
Completion. The installation of permanent equipment for the production of crude oil or natural
gas. Completion of the well does not necessarily mean the well will be profitable.
Completion Rate. The number of wells on which production casing has been run for a completion
attempt as a percentage of the number of wells drilled.
Development Well. A well drilled within the proved area of an crude oil or natural gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Well. A well found to be incapable of producing either crude oil or natural gas in
sufficient quantities to justify completion of an crude oil or gas well.
Early Production Rate. The peak 24 hour production rate of a well, usually achieved within the
first few days after being brought on line to production.
Exploratory Well. A well drilled to find and produce crude oil or natural gas in an unproved
area, to find a new reservoir in a field previously found to be productive of crude oil or gas in
another reservoir, or to extend a known reservoir.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a
working interest.
Hydraulic fracturing. A stimulation treatment routinely performed on crude oil and gas wells
in low-permeability reservoirs. Specially engineered fluids are pumped at high pressure and rate
into the reservoir interval to be treated, causing a vertical fracture to open. The wings of the
fracture extend away from the wellbore in opposing directions according to the natural stresses
within the formation.
Lease Operating Expenses. The expenses, usually recurring, which pay for operating the wells
and equipment on a producing lease.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
|
|
MBoe. One thousand barrels of crude oil equivalent. |
Mcf. One thousand cubic feet of natural gas.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
67
Mcfe. One thousand cubic feet of natural gas equivalents.
MMBtu. One million Btu, or British Thermal Units. One British Thermal Unit is the quantity of
heat required to raise the temperature of one pound of water by one degree Fahrenheit.
MMcf. One million cubic feet of natural gas.
MMcfe. One million cubic feet of natural gas equivalents.
Net Acres or Net Wells. Gross acres or wells multiplied, in each case, by the percentage
working interest we own.
Net Production. Production that we own less royalties and production due others.
Oil. Crude oil, condensate or other liquid hydrocarbons.
Operator. The individual or company responsible for the exploration, development, and
production of an oil or gas well or lease.
Pay. The vertical thickness of an oil and gas producing zone. Pay can be measured as either
gross pay, including non-productive zones or net pay, including only zones that appear to be
productive based upon logs and test data.
Pre-tax PV10%. The pre-tax present value of estimated future revenues to be generated from the
production of proved reserves calculated in accordance with Securities and Exchange Commission
guidelines, net of estimated production and future development costs, using prices and costs as of
the date of estimation without future escalation, without giving effect to non-property related
expenses such as general and administrative expenses, debt service and depreciation, depletion and
amortization, and discounted using an annual discount rate of 10%.
Proved Developed Reserves. Reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids,
which geological and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major expenditure is required for
recompletion.
Royalty. An interest in an oil and gas lease that gives the owner of the interest the right to
receive a portion of the production from the leased acreage (or of the proceeds of the sale
thereof), but generally does not require the owner to pay any portion of the costs of drilling or
operating the wells on the leased acreage. Royalties may be either landowners royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or overriding
royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to
a subsequent owner.
Spud. Start (or restart) drilling a new well.
Standardized Measure. The after-tax present value of estimated future revenues to be generated
from the production of proved reserves calculated in accordance with Securities and Exchange
Commission guidelines, net of estimated production and future development costs, using prices and
costs as of the date of estimation without future escalation, without giving effect to non-property
related expenses such as general and administrative expenses, debt service and depreciation,
depletion and amortization, and discounted using an annual discount rate of 10%.
Working Interest. An interest in an oil and gas lease that gives the owner of the interest the
right to drill for and produce crude oil and natural gas on the leased acreage and requires the
owner to pay a share of the costs of drilling and production operations.
68
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, hereunder
duly authorized, as of February 28, 2011.
|
|
|
|
|
|
BRIGHAM EXPLORATION COMPANY
|
|
|
By: |
/s/ BEN M. BRIGHAM
|
|
|
|
Ben M. Brigham |
|
|
|
Chief Executive Officer,
President and Chairman of the Board |
|
Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on
behalf of the Registrant and in the capacity indicated have signed this report below as of February
28, 2011.
|
|
|
/s/ BEN M. BRIGHAM
Ben M. Brigham
|
|
Chief Executive Officer, President and Chairman of the Board
(Principal Executive Officer) |
|
|
|
/s/ EUGENE B. SHEPHERD, JR.
Eugene B. Shepherd, Jr.
|
|
Executive Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer) |
|
|
|
/s/ DAVID T. BRIGHAM
David T. Brigham
|
|
Executive Vice President Land and Administration and
Director |
|
|
|
/s/ HAROLD D. CARTER
Harold D. Carter
|
|
Director |
|
|
|
/s/ STEPHEN C. HURLEY
Stephen C. Hurley
|
|
Director |
|
|
|
/s/ STEPHEN P. REYNOLDS
Stephen P. Reynolds
|
|
Director |
|
|
|
/s/ HOBART A. SMITH
Hobart A. Smith
|
|
Director |
|
|
|
/s/ SCOTT W. TINKER
Scott W. Tinker
|
|
Director |
69
BRIGHAM EXPLORATION COMPANY
INDEX TO FINANCIAL STATEMENTS
|
|
|
|
|
Page |
|
|
|
|
|
F-2 |
|
|
|
|
|
F-4 |
|
|
|
|
|
F-5 |
|
|
|
|
|
F-6 |
|
|
|
|
|
F-7 |
|
|
|
|
|
F-8 |
|
|
|
|
|
F-29 |
|
|
|
|
|
F-32 |
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Brigham Exploration Company:
We have audited the accompanying consolidated balance sheets of Brigham Exploration Company
and subsidiaries (the Company) as of December 31, 2010 and 2009, and the related consolidated
statements of operations, stockholders equity, and cash flows for each of the years in the
three-year period ended December 31, 2010. These consolidated financial statements are the
responsibility of the Companys management. Our responsibility is to express an opinion on these
consolidated financial statements based on our 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 Brigham Exploration Company and subsidiaries as of
December 31, 2010 and 2009, and the results of their operations and their cash flows for each of
the years in the three-year period ended December 31, 2010, in conformity with U.S. generally
accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Brigham Exploration Companys internal control over financial
reporting as of December 31, 2010, based on criteria established in Internal Control Integrated
Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
and our report dated March 1, 2011 expressed an unqualified opinion on the effectiveness of the
Companys internal control over financial reporting.
(signed) KPMG LLP
Dallas, Texas
March 1, 2011
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Brigham Exploration Company:
We have audited Brigham Exploration Companys (the Company) internal control over financial
reporting as of December 31, 2010, based on criteria established in Internal Control Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
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 (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Brigham Exploration Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2010, based on criteria established in
Internal Control Integrated Framework, issued by the Committee of Sponsoring Organizations of
the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of Brigham Exploration Company and
subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of
operations, stockholders equity, and cash flows for each of the years in the three-year period
ended December 31, 2010, and our report dated March 1, 2011 expressed an unqualified opinion on
those consolidated financial statements.
(signed) KPMG LLP
Dallas, Texas
March 1, 2011
F-3
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
23,743 |
|
|
$ |
40,781 |
|
Accounts receivable |
|
|
70,368 |
|
|
|
21,194 |
|
Short term investments |
|
|
223,991 |
|
|
|
80,093 |
|
Inventory |
|
|
34,959 |
|
|
|
14,087 |
|
Other current assets |
|
|
7,796 |
|
|
|
2,284 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
360,857 |
|
|
|
158,439 |
|
|
|
|
|
|
|
|
Oil and natural gas properties, using the full cost method of accounting |
|
|
|
|
|
|
|
|
Proved |
|
|
910,114 |
|
|
|
619,920 |
|
Unproved |
|
|
182,933 |
|
|
|
76,309 |
|
Accumulated depletion |
|
|
(423,691 |
) |
|
|
(365,496 |
) |
|
|
|
|
|
|
|
|
|
|
669,356 |
|
|
|
330,733 |
|
|
|
|
|
|
|
|
Other property and equipment, net |
|
|
42,837 |
|
|
|
3,025 |
|
Deferred loan fees |
|
|
9,064 |
|
|
|
5,213 |
|
Other noncurrent assets |
|
|
3,287 |
|
|
|
846 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,085,401 |
|
|
$ |
498,256 |
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
50,023 |
|
|
$ |
19,251 |
|
Royalties payable |
|
|
42,155 |
|
|
|
8,268 |
|
Accrued drilling costs |
|
|
61,067 |
|
|
|
15,498 |
|
Participant advances received |
|
|
3,037 |
|
|
|
6,949 |
|
Series A Preferred Stock, mandatorily redeemable, $.01 par value,
$20 stated and redemption value, 2,250,000 shares authorized,
505,051 shares issued and outstanding at December 31, 2009 |
|
|
|
|
|
|
10,101 |
|
Derivative liabilities |
|
|
9,442 |
|
|
|
2,405 |
|
Other current liabilities |
|
|
10,821 |
|
|
|
5,301 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
176,545 |
|
|
|
67,773 |
|
|
|
|
|
|
|
|
Senior Notes |
|
|
300,000 |
|
|
|
158,968 |
|
Deferred income taxes |
|
|
1,088 |
|
|
|
|
|
Other noncurrent liabilities |
|
|
14,498 |
|
|
|
7,232 |
|
Commitments and contingencies (Note 10) |
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Common stock, $.01 par value, 180 million shares authorized,
116,564,182 and 99,593,075 shares issued and 116,289,180 and 99,351,825
shares outstanding at December 31, 2010 and 2009, respectively |
|
|
1,166 |
|
|
|
996 |
|
Additional paid-in capital |
|
|
765,326 |
|
|
|
479,077 |
|
Treasury stock, at cost; 275,002 and 241,250 shares at December 31,
2010 and 2009, respectively |
|
|
(2,657 |
) |
|
|
(2,133 |
) |
Accumulated other comprehensive income (loss) |
|
|
(9 |
) |
|
|
(205 |
) |
Retained earnings (deficit) |
|
|
(170,556 |
) |
|
|
(213,452 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
593,270 |
|
|
|
264,283 |
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
1,085,401 |
|
|
$ |
498,256 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-4
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
179,279 |
|
|
$ |
68,192 |
|
|
$ |
125,108 |
|
Gain (loss) on derivatives, net |
|
|
(10,066 |
) |
|
|
2,064 |
|
|
|
2,548 |
|
Support infrastructure |
|
|
489 |
|
|
|
|
|
|
|
|
|
Other revenue |
|
|
20 |
|
|
|
88 |
|
|
|
132 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
169,722 |
|
|
|
70,344 |
|
|
|
127,788 |
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
|
18,651 |
|
|
|
14,655 |
|
|
|
12,363 |
|
Production taxes |
|
|
17,313 |
|
|
|
5,098 |
|
|
|
5,374 |
|
Support infrastructure |
|
|
50 |
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
12,943 |
|
|
|
9,243 |
|
|
|
9,557 |
|
Depletion of oil and natural gas properties |
|
|
58,195 |
|
|
|
32,054 |
|
|
|
53,498 |
|
Impairment of oil and natural gas properties |
|
|
|
|
|
|
114,781 |
|
|
|
237,180 |
|
Depreciation and amortization |
|
|
1,704 |
|
|
|
812 |
|
|
|
629 |
|
Accretion of discount on asset retirement obligations |
|
|
422 |
|
|
|
421 |
|
|
|
361 |
|
Loss on inventory valuation |
|
|
|
|
|
|
2,196 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
109,278 |
|
|
|
179,260 |
|
|
|
318,962 |
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
60,444 |
|
|
|
(108,916 |
) |
|
|
(191,174 |
) |
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
1,198 |
|
|
|
578 |
|
|
|
191 |
|
Interest expense, net |
|
|
(11,448 |
) |
|
|
(16,431 |
) |
|
|
(14,495 |
) |
Loss on early redemption of Senior Notes |
|
|
(11,308 |
) |
|
|
|
|
|
|
|
|
Other income (expense) |
|
|
5,094 |
|
|
|
1,544 |
|
|
|
530 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16,464 |
) |
|
|
(14,309 |
) |
|
|
(13,774 |
) |
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
43,980 |
|
|
|
(123,225 |
) |
|
|
(204,948 |
) |
Income tax benefit (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred |
|
|
(1,084 |
) |
|
|
233 |
|
|
|
42,701 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,084 |
) |
|
|
233 |
|
|
|
42,701 |
|
|
|
|
|
|
|
|
|
|
|
Net Income (loss) |
|
$ |
42,896 |
|
|
$ |
(122,992 |
) |
|
$ |
(162,247 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share available to common stockholders: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.39 |
|
|
$ |
(1.74 |
) |
|
$ |
(3.57 |
) |
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.38 |
|
|
$ |
(1.74 |
) |
|
$ |
(3.57 |
) |
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
111,355 |
|
|
|
70,569 |
|
|
|
45,441 |
|
Diluted |
|
|
113,308 |
|
|
|
70,569 |
|
|
|
45,441 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F-5
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
Retained |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
Comprehensive |
|
|
Earnings |
|
|
Total |
|
|
|
Common Stock |
|
|
Paid In |
|
|
Treasury |
|
|
Income |
|
|
(Accumulated |
|
|
Stockholders |
|
|
|
Shares |
|
|
Amounts |
|
|
Capital |
|
|
Stock |
|
|
(Loss) |
|
|
Deficit) |
|
|
Equity |
|
Balance, December 31, 2007 |
|
|
45,304 |
|
|
$ |
453 |
|
|
$ |
207,526 |
|
|
$ |
(854 |
) |
|
$ |
115 |
|
|
$ |
71,787 |
|
|
$ |
279,027 |
|
Comprehensive income
(loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(162,247 |
) |
|
|
(162,247 |
) |
Tax provisions related
to cash flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61 |
|
|
|
|
|
|
|
61 |
|
Net (gains) losses
included in net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(176 |
) |
|
|
|
|
|
|
(176 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(162,362 |
) |
Issuance of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vesting of restricted stock |
|
|
139 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of employee stock
options |
|
|
386 |
|
|
|
4 |
|
|
|
2,062 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,066 |
|
Repurchases of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(348 |
) |
|
|
|
|
|
|
|
|
|
|
(348 |
) |
Vesting of share-based
payments |
|
|
|
|
|
|
|
|
|
|
2,886 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,886 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008 |
|
|
45,829 |
|
|
$ |
458 |
|
|
$ |
212,473 |
|
|
$ |
(1,202 |
) |
|
$ |
|
|
|
$ |
(90,460 |
) |
|
$ |
121,269 |
|
Comprehensive income
(loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(122,992 |
) |
|
|
(122,992 |
) |
Tax provisions related
to cash flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(205 |
) |
|
|
|
|
|
|
(205 |
) |
Net (gains) losses
included in net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(123,197 |
) |
Issuance of common stock |
|
|
53,130 |
|
|
|
532 |
|
|
|
261,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
261,725 |
|
Vesting of restricted stock |
|
|
378 |
|
|
|
4 |
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of employee stock
options |
|
|
256 |
|
|
|
2 |
|
|
|
1,217 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,219 |
|
Repurchases of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(931 |
) |
|
|
|
|
|
|
|
|
|
|
(931 |
) |
Vesting of share-based
payments |
|
|
|
|
|
|
|
|
|
|
4,198 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,198 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009 |
|
|
99,593 |
|
|
$ |
996 |
|
|
$ |
479,077 |
|
|
$ |
(2,133 |
) |
|
$ |
(205 |
) |
|
$ |
(213,452 |
) |
|
$ |
264,283 |
|
Comprehensive income
(loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,896 |
|
|
|
42,896 |
|
Unrealized gains (loss)
on investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
196 |
|
|
|
|
|
|
|
196 |
|
Tax benefits (provisions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
(loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43,092 |
|
Issuance of common stock |
|
|
16,100 |
|
|
|
161 |
|
|
|
277,386 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
277,547 |
|
Vesting of restricted stock |
|
|
130 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of employee stock
options |
|
|
741 |
|
|
|
8 |
|
|
|
3,876 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,884 |
|
Repurchases of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(524 |
) |
|
|
|
|
|
|
|
|
|
|
(524 |
) |
Vesting of share-based
payments |
|
|
|
|
|
|
|
|
|
|
4,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010 |
|
|
116,564 |
|
|
$ |
1,166 |
|
|
$ |
765,326 |
|
|
$ |
(2,657 |
) |
|
$ |
(9 |
) |
|
$ |
(170,556 |
) |
|
$ |
593,270 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-6
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
42,896 |
|
|
$ |
(122,992 |
) |
|
$ |
(162,247 |
) |
Adjustments to reconcile net income (loss) to cash provided
(used) by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of oil and natural gas properties |
|
|
58,195 |
|
|
|
32,054 |
|
|
|
53,498 |
|
Impairment of oil and natural gas properties |
|
|
|
|
|
|
114,781 |
|
|
|
237,180 |
|
Depreciation and amortization |
|
|
1,704 |
|
|
|
812 |
|
|
|
629 |
|
Stock based compensation |
|
|
2,676 |
|
|
|
2,278 |
|
|
|
1,592 |
|
Amortization of discount and deferred loan fees |
|
|
2,025 |
|
|
|
1,635 |
|
|
|
1,105 |
|
Loss on early redemption of Senior Notes |
|
|
11,308 |
|
|
|
|
|
|
|
|
|
Accretion of discount on asset retirement obligations |
|
|
422 |
|
|
|
421 |
|
|
|
361 |
|
Market value adjustment for derivative instruments |
|
|
13,175 |
|
|
|
7,313 |
|
|
|
(6,140 |
) |
Deferred income taxes |
|
|
1,084 |
|
|
|
(233 |
) |
|
|
(42,701 |
) |
Provision for doubtful accounts |
|
|
146 |
|
|
|
(19 |
) |
|
|
17 |
|
Other noncash items |
|
|
|
|
|
|
90 |
|
|
|
4 |
|
Changes in working capital and other items: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(49,320 |
) |
|
|
3,383 |
|
|
|
(9,966 |
) |
Other current assets |
|
|
(4,106 |
) |
|
|
803 |
|
|
|
(6,521 |
) |
Accounts and royalties payable |
|
|
64,659 |
|
|
|
6,363 |
|
|
|
2,877 |
|
Other current liabilities |
|
|
1,608 |
|
|
|
4,964 |
|
|
|
500 |
|
Noncurrent assets |
|
|
(1,524 |
) |
|
|
114 |
|
|
|
(330 |
) |
Noncurrent liabilities |
|
|
(428 |
) |
|
|
(17 |
) |
|
|
(228 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
144,520 |
|
|
|
51,750 |
|
|
|
69,630 |
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties |
|
|
(367,245 |
) |
|
|
(74,668 |
) |
|
|
(178,637 |
) |
Proceeds from sale of oil and natural gas properties |
|
|
17,918 |
|
|
|
|
|
|
|
|
|
Changes in inventory |
|
|
(20,872 |
) |
|
|
(7,881 |
) |
|
|
|
|
Additions to other property and equipment |
|
|
(41,516 |
) |
|
|
(2,054 |
) |
|
|
(1,472 |
) |
Purchases of short term investments |
|
|
(331,624 |
) |
|
|
(86,575 |
) |
|
|
|
|
Sales of short term investments |
|
|
187,922 |
|
|
|
6,277 |
|
|
|
|
|
(Increase) decrease in drilling advances paid |
|
|
(794 |
) |
|
|
(274 |
) |
|
|
798 |
|
Changes to restricted cash |
|
|
|
|
|
|
555 |
|
|
|
(555 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(556,211 |
) |
|
|
(164,620 |
) |
|
|
(179,866 |
) |
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common stock, net of issuance costs |
|
|
277,547 |
|
|
|
261,725 |
|
|
|
|
|
Proceeds from exercise of employee stock options |
|
|
3,884 |
|
|
|
1,219 |
|
|
|
2,066 |
|
Proceeds from Senior Notes offering |
|
|
300,000 |
|
|
|
|
|
|
|
|
|
Redemption of Senior Notes offering |
|
|
(168,683 |
) |
|
|
|
|
|
|
|
|
Redemption of Series A Preferred Stock |
|
|
(10,101 |
) |
|
|
|
|
|
|
|
|
Repurchases of common stock |
|
|
(524 |
) |
|
|
(931 |
) |
|
|
(348 |
) |
Increase in senior credit facility |
|
|
|
|
|
|
|
|
|
|
139,500 |
|
Repayment of senior credit facility |
|
|
|
|
|
|
(145,000 |
) |
|
|
(4,500 |
) |
Deferred loan fees paid and equity costs |
|
|
(7,470 |
) |
|
|
(3,405 |
) |
|
|
(302 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
394,653 |
|
|
|
113,608 |
|
|
|
136,416 |
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
(17,038 |
) |
|
|
738 |
|
|
|
26,180 |
|
Cash and cash equivalents, beginning of year |
|
|
40,781 |
|
|
|
40,043 |
|
|
|
13,863 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of year |
|
$ |
23,743 |
|
|
$ |
40,781 |
|
|
$ |
40,043 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-7
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Brigham Exploration Company is a Delaware corporation formed on February 25, 1997 for the
purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership
interests of Brigham Oil & Gas, L.P. (the Partnership). Hereinafter, Brigham Exploration Company
and the Partnership are collectively referred to as Brigham. The Partnership was formed in May
1992 to explore and develop onshore domestic oil and natural gas properties using 3-D seismic
imaging and other advanced technologies. Brighams exploration and development of oil and natural
gas properties is currently focused in the Williston Basin, the Gulf Coast, the Anadarko Basin, and
West Texas and Other.
2. Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting
principles in the United States of America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. The most significant estimates relate to proved oil and
natural gas reserve volumes, future development costs, estimates relating to certain oil and
natural gas revenues and expenses, and deferred income taxes. Actual results may differ from those
estimates.
Reclassifications
Certain reclassifications have been made to prior years reported amounts in order to conform
with the current year presentation. These reclassifications did not impact our net income,
stockholders equity or cash flows.
Principles of Consolidation
The accompanying financial statements include the accounts of Brigham and its wholly owned
subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the
limited partnerships in which Brigham, or any of its subsidiaries has a participating interest. All
significant intercompany accounts and transactions have been eliminated.
Cash and Cash Equivalents
Brigham considers all highly liquid financial instruments with an original maturity of three
months or less to be cash equivalents.
Investments
Investments consist primarily of certificates of deposit, corporate debt, and government
securities, all of which are classified as available-for-sale and stated at fair value.
Accordingly, unrealized gains and losses and any related deferred income tax effects are excluded
from earnings and reported as a separate component of stockholders equity. Realized gains or
losses are computed based on specific identification of the securities sold.
F-8
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Inventory
Inventory, which is included in current assets, includes tubular goods and other lease and
well equipment which we plan to utilize in our ongoing exploration and development activities.
Inventory also includes barrels of crude oil that was produced in the Williston Basin during
operations but not yet sold at year-end in the amount of 46,129 barrels and 16,475 barrels at
December 31, 2010 and 2009, respectively. Inventories are carried at the lower of cost or market
using the specific identification method. Crude oil was valued at Brighams estimated production
cost of $299,000 and $136,000 at December 31, 2010 and 2009, respectively.
Property and Equipment
Brigham uses the full cost method of accounting for oil and natural gas properties. Under this
method, all acquisition, exploration and development costs, including certain payroll, asset
retirement costs, other internal costs, and interest incurred for the purpose of finding oil and
natural gas reserves, are capitalized. Internal costs that are capitalized are directly
attributable to acquisition, exploration and development activities and do not include costs
related to production, general corporate overhead or similar activities. Costs associated with
production and general corporate activities are expensed in the period incurred. Proceeds from the
sale of oil and natural gas properties are applied to reduce the capitalized costs of oil and
natural gas properties unless the sale would significantly alter the relationship between
capitalized costs and proved reserves, in which case a gain or loss is recognized.
Capitalized costs associated with impaired properties and capitalized costs related to
properties having proved reserves, plus the estimated future development costs, and asset
retirement costs under Financial Accounting Standards Board Accounting Standards Codification Topic
410 Asset Retirement and Environmental Obligations (FASB ASC 410), are amortized using the
unit-of-production method based on proved reserves. Capitalized costs of oil and natural gas
properties, net of accumulated amortization and deferred income taxes, are limited to the total of
estimated future net cash flows from proved oil and natural gas reserves, discounted at ten
percent, plus the cost of unevaluated properties. The estimated future net cash flows at December
31, 2008 were determined using prices at the end of the year. Under certain specific conditions,
companies could elect to use subsequent prices for determining the estimated future net cash flows.
Brigham elected to use subsequent pricing for this purpose at December 31, 2008. Under new rules
issued by the Securities and Exchange Commission, the estimated future net cash flows for at
December 31, 2010 and 2009 were determined using a 12-month average price. The average is
calculated using the first day of the month price for each of the 12 months that make up the
reporting period. The use of subsequent pricing is no longer allowed. See New Pronouncements
below for additional detail regarding the new rules. There are many factors, including global
events that may influence the production, processing, marketing and price of oil and natural gas. A
reduction in the valuation of oil and natural gas properties resulting from declining prices or
production could adversely impact depletion rates and capitalized cost limitations. Capitalized
costs associated with properties that have not been evaluated through drilling or seismic analysis,
including exploration wells in progress at December 31, 2010 and 2009, are excluded from the
unit-of-production amortization. Exclusions are adjusted annually based on drilling results and
interpretative analysis.
Other property and equipment, which primarily consists of water disposal wells and gathering
systems, is depreciated on a straight-line basis over the estimated useful lives of the assets
after considering salvage value. Estimated useful lives are as follows:
|
|
|
|
|
Support infrastructure wells and gathering systems |
|
15 years |
Furniture and fixtures |
|
10 years |
Machinery and equipment |
|
3 10 years |
3-D seismic interpretation workstations and software |
|
3 years |
Pipeyard equipment and improvements |
|
7 15 years |
Field general equipment |
|
3 15 years |
Land |
|
|
|
|
Betterments and major improvements that extend the useful lives are capitalized while
expenditures for repairs and maintenance of a minor nature are expensed as incurred.
F-9
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Asset Retirement Obligations
Brigham records the fair value of a liability for an asset retirement obligation in the period
in which it is incurred and a corresponding increase in the carrying amount of the related
long-lived asset. The liability is accreted to its present value each period, and the capitalized
cost is depreciated over the useful life of the related asset. If the liability is settled for an
amount other than the recorded amount, a gain or loss is recognized.
Revenue Recognition
Brigham recognizes revenues from the sale of crude oil using the sales method of accounting.
Under this method, Brigham recognizes revenues when oil is delivered and title transfers.
Brigham recognizes revenues from the sale of natural gas using the entitlements method of
accounting. Under this method, revenues are recognized based on Brighams entitled ownership
percentage of sales of natural gas to purchasers. Gas imbalances occur when Brigham sells more or
less than its entitled ownership percentage of total natural gas production. When Brigham receives
less than its entitled share, a receivable is recorded. When Brigham receives more than its
entitled share, a liability is recorded.
Brigham recognizes revenue from its support infrastructure operations, which provide the usage
of its oil, natural gas, waste water and fresh water gathering lines. Brigham also provides water
disposal services for certain operated wells currently drilling or that have been placed on
production. Any intercompany revenues and expenses have been eliminated for financial statement
presentation.
Derivative Instruments and Hedging Activities
Brigham accounts for its derivative activities under Financial Accounting Standards Board
Accounting Standards Codification Topic 815 Derivatives and Hedging (FASB ASC 815). FASB ASC 815
establishes accounting and reporting standards requiring that every derivative instrument be
recorded on the balance sheet as either an asset or a liability measured at its fair value. The
statement requires that changes in the derivatives fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Brigham uses derivative instruments to manage
market risks resulting from fluctuations in the prices of crude oil and natural gas. Brigham
periodically enters into derivative contracts, including price swaps, ceilings and floors, which
require payments to (or receipts from) counterparties based on the differential between a fixed
price and a variable price for a fixed quantity of oil or natural gas without the exchange of
underlying volumes. The notional amounts of these financial instruments are based on expected
production from existing wells.
At the inception of a derivative contract, Brigham historically designated the derivative as a
cash flow hedge. Derivatives were recorded on the balance sheet at fair value and changes in the
fair value of derivatives were recorded each period in net income or other comprehensive income,
depending on whether a derivative was designated as part of a hedge transaction and, if it was,
depending on the type of hedge transaction. On October 1, 2006, Brigham de-designated all derivates
that were previously classified as cash flow hedges and, in addition, Brigham elected not to
designate any additional derivative contracts as accounting hedges under FASB ASC Topic 815. As
such, all derivative positions are carried at their fair value on the consolidated balance sheet
and are marked-to-market at the end of each period. Any realized and unrealized gains or losses are
recorded as gain (loss) on derivatives, net, as an increase or decrease in revenue on the
consolidated statement of operations rather than as a component of other comprehensive income or
other income (expense).
Other Comprehensive Income (Loss)
Brigham follows the provisions of Financial Accounting Standards Board Accounting Standards
Codification Topic 220 Comprehensive Income (FASB ASC 220), which establishes standards for
reporting comprehensive income. In addition to net income (loss), comprehensive income (loss)
includes all changes in equity during a period, except those resulting from investments and
distributions to stockholders of Brigham.
F-10
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table reflects the components of other comprehensive income (loss) for the years
ended December 31, 2010, 2009 and 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Balance, beginning of year |
|
$ |
(205 |
) |
|
$ |
|
|
|
$ |
115 |
|
Unrealized (gains) losses on investments |
|
|
196 |
|
|
|
(205 |
) |
|
|
|
|
Tax benefits (provisions) related to cash flow hedges |
|
|
|
|
|
|
|
|
|
|
61 |
|
Net (gains) losses included in earnings |
|
|
|
|
|
|
|
|
|
|
(176 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
$ |
(9 |
) |
|
$ |
(205 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
Stock Based Compensation
Brigham applies Financial Accounting Standards Board Accounting Standards Codification Topic
718 Compensation Stock Compensation (FASB ASC 718) to account for stock based compensation.
See Note 13, Stock Based Compensation, for a full discussion of our stock-based compensation.
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 of deferred tax assets and liabilities is
recognized in income in the year of the enacted rate change. Deferred tax assets are reduced by a
valuation allowance when, in the opinion of management, it is more likely than not that some
portion or all of the deferred tax assets will not be realized.
Deferred Loan Fees
Deferred loan fees incurred in connection with the issuance of debt are recorded on the
balance sheet in other noncurrent assets. The debt issue costs are amortized to interest expense
over the life of the debt using the straight-line method. The results obtained using the
straight-line method are not materially different than those that would result from using the
effective interest method.
Segment Information
All of Brighams oil and natural gas properties and related operations are located onshore in
the United States and management has determined that Brigham has one reportable segment.
Treasury Stock
Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares
held is reduced by the average purchase price per share of the aggregate treasury shares held.
Mandatorily Redeemable Preferred Stock
The Series A Preferred Stock is presented in accordance with Financial Accounting Standards
Board Accounting Standards Codification Topic 480 Distinguishing Liabilities from Equity (FASB
ASC 480). FASB ASC 480 requires an issuer to classify certain financial instruments within its
scope, such as mandatorily redeemable preferred stock, as liabilities (or assets in some
circumstances). FASB ASC 480 defines a financial instrument as mandatorily redeemable if it
embodies an unconditional obligation requiring the issuer to redeem the instrument by transferring
its assets at a specified or determinable date(s) or upon an event certain to occur.
F-11
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
New Pronouncements
On December 31, 2008, the SEC published the final rules and interpretations updating its oil
and gas reporting requirements. Many of the revisions are updates to definitions in the existing
oil and gas rules to make them consistent with the petroleum resource management system, which is a
widely accepted standard for the management of petroleum resources that was developed by several
industry organizations. Key revisions include the ability to include nontraditional resources in
reserves, the use of new technology for determining reserves, permitting disclosure of probable and
possible reserves, and changes to the pricing used to determine reserves in that companies must use
a 12-month average price. The average is calculated using the first-day-of-the-month price for each
of the 12 months that make up the reporting period. The SEC required companies to comply with the
amended disclosure requirements for registration statements filed after January 1, 2010, and for
annual reports for fiscal years ending on or after December 15, 2009. Early adoption was not
permitted. Financial Accounting Standards Board Accounting Standards Codification Topic 932
Extractive Activities Oil and Gas (FASB ASC 932) provides guidance for oil and natural gas
reserve related disclosures in the financial statements. Adoption of the new requirements did not
have a material impact on Brighams financial statements.
3. Property and Equipment
Property and equipment, at cost, are summarized as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Oil and natural gas properties |
|
$ |
1,093,047 |
|
|
$ |
696,229 |
|
Accumulated depletion |
|
|
(423,691 |
) |
|
|
(365,496 |
) |
|
|
|
|
|
|
|
|
|
|
669,356 |
|
|
|
330,733 |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Other property and equipment: |
|
|
|
|
|
|
|
|
Support infrastructure wells and gathering systems |
|
|
32,543 |
|
|
|
|
|
3-D seismic interpretation workstations and software |
|
|
1,627 |
|
|
|
1,619 |
|
Office furniture and equipment |
|
|
3,646 |
|
|
|
3,307 |
|
Pipeyard equipment and improvements |
|
|
3,686 |
|
|
|
832 |
|
Field general equipment |
|
|
6,655 |
|
|
|
1,739 |
|
Land |
|
|
1,264 |
|
|
|
409 |
|
Accumulated depreciation |
|
|
(6,584 |
) |
|
|
(4,881 |
) |
|
|
|
|
|
|
|
|
|
|
42,837 |
|
|
|
3,025 |
|
|
|
|
|
|
|
|
|
|
$ |
712,193 |
|
|
$ |
333,758 |
|
|
|
|
|
|
|
|
F-12
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Depletion expense is based on units-of-production. Production volumes used to determine
depletion expense were 2,976 MBoe, 1,796 MBoe, and 1,910 MBoe for 2010, 2009, and 2008
respectively. The depletion rate used to calculate depletion expense was $19.56, $17.88, and $28.02
for 2010, 2009, and 2008, respectively.
Brigham capitalizes certain payroll and other internal costs directly attributable to
acquisition, exploration and development activities as part of its investment in oil and natural
gas properties over the periods benefited by these activities. Capitalized costs do not include any
costs related to production, general corporate overhead, or similar activities. Capitalized costs
are summarized as follows for the years ended December 31, 2010, 2009 and 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Capitalized certain payroll and other internal costs |
|
$ |
12,552 |
|
|
$ |
7,718 |
|
|
$ |
7,994 |
|
Capitalized interest costs |
|
|
9,770 |
|
|
|
4,713 |
|
|
|
4,761 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
22,322 |
|
|
$ |
12,431 |
|
|
$ |
12,755 |
|
|
|
|
|
|
|
|
|
|
|
The risk that Brigham will experience a ceiling test writedown increases when oil and gas
prices are depressed or if Brigham has substantial downward revisions in its estimated proved
reserves. Based on oil and gas prices in effect at the end of December 2008 ($5.710 per MMBtu for
Henry Hub natural gas and $44.60 per barrel for West Texas Intermediate oil, adjusted for
differentials), the unamortized cost of Brighams oil and gas properties exceeded the ceiling limit
by $148.6 million, net of tax. As a result, Brigham was required to record a writedown of the net
capitalized costs of its oil and gas properties in the amount of $237.2 million at December 31,
2008.
Based on oil and gas prices in effect at the end of March 2009 ($3.63 per MMBtu for Henry Hub
gas and $49.65 per barrel for West Texas Intermediate oil, adjusted for differentials), the
unamortized cost of Brighams oil and gas properties exceeded the ceiling limit by $71.9 million,
net of tax. As a result, Brigham was required to record a writedown of the net capitalized costs of
its oil and gas properties in the amount of $114.8 million at March 31, 2009. Based on the 12-month
average oil and gas prices for the year ended December 31, 2009 ($3.87 per MMBtu for Henry Hub
natural gas and $61.18 per barrel for West Texas Intermediate oil, adjusted for differentials), the
unamortized cost of Brighams oil and gas properties did not exceed the ceiling limit. Therefore,
Brigham was not required to writedown the net capitalized costs of its oil and gas properties at
December 31, 2009.
Based on the 12-month average oil and gas prices for the year ended December 31, 2010 ($4.38
per MMBtu for Henry Hub natural gas and $79.43 per barrel for West Texas Intermediate oil, adjusted
for differentials), the unamortized cost of Brighams oil and gas properties did not exceed the
ceiling limit. Therefore, Brigham was not required to writedown the net capitalized costs of its
oil and gas properties at December 31, 2010.
During the second quarter 2010, Brigham sold a portion of its proved developed producing West
Texas assets for $14 million with an effective date of January 1, 2010. The proceeds for the sale
were applied to reduce the capitalized costs of oil and gas properties
4. Common Stock
In May 2009, Brigham completed a public offering of common stock pursuant to a shelf
registration statement. Brigham sold 36,292,117 shares of its common stock at a price of $2.75 per
share and received net proceeds of $93.4 million after underwriting fees and offering expenses.
In October 2009, Brigham completed a public offering of common stock pursuant to a shelf
registration statement. Brigham sold 16,000,000 shares of its common stock at a price of $10.50
per share and received net proceeds of $159.9 million after underwriting fees and offering
expenses. In November 2009, the underwriters elected to exercise a portion of the over-allotment
option associated with this equity offering. Brigham issued 837,523 additional shares of common
stock and received net proceeds of $8.4 million after underwriting fees and offering expenses.
In April 2010, Brigham completed a public offering of common stock pursuant to a shelf
registration statement. Brigham sold 16,100,000 shares of its common stock at a price of $18.00
per share and received net proceeds of approximately $277.5 million after deducting underwriting
fees and offering expenses.
F-13
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Senior Credit Facility and Senior Notes
The following table reflects the outstanding balances of the senior credit facility and senior
notes for the years ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In thousands) |
|
Senior Credit Facility |
|
$ |
|
|
|
$ |
|
|
Senior Notes |
|
|
300,000 |
|
|
|
160,000 |
|
Discount on Senior Notes |
|
|
|
|
|
|
(1,032 |
) |
|
|
|
|
|
|
|
Total Debt |
|
$ |
300,000 |
|
|
$ |
158,968 |
|
Less: Current Maturities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Long-Term Debt |
|
$ |
300,000 |
|
|
$ |
158,968 |
|
|
|
|
|
|
|
|
Senior Credit Facility
In May 2009, in conjunction with Brighams regularly scheduled semi-annual redetermination and
Brighams common stock offering, the borrowing base was reset to $110 million. On July 24, 2009,
Brigham amended and restated the Senior Credit Facility to extend the maturity of the agreement
from June 2010 to July 2012. During October 2009, Brigham used a portion of the proceeds from the
October stock offering to repay borrowings under the Senior Credit Facility of $110 million.
Brigham had no borrowings outstanding under its Senior Credit Facility at December 31, 2010 and
2009.
Borrowings under the Senior Credit Facility bear interest, at Brighams election, at a base
rate (as the term was defined in the Senior Credit Facility) or Eurodollar rate, plus in each case
an applicable margin that was reset quarterly (2.5% at December 31, 2010). The applicable interest
rate margin varied from 1.5% to 2.5% in the case of borrowings based on the base rate (as the term
was defined in the Senior Credit Facility) and from 2.5% to 3.5% in the case of borrowings based on
the Eurodollar rate, depending on percentage of the available borrowing base utilized. In
addition, Brigham was required to pay a commitment fee on the unused portion of its borrowing base
(0.50% at December 31, 2010). Borrowings under the Senior Credit Facility were collateralized by
substantially all of Brighams oil and natural gas properties under first liens.
The Senior Credit Facility contained various covenants, including among other restrictions on
liens, restrictions on incurring other indebtedness, restrictions on mergers, restrictions on
investments, and restrictions on hedging activity of a speculative nature or with counterparties
having credit ratings below specified levels. The Senior Credit Facility required Brigham to
maintain a current ratio (as defined) of at least 1 to 1. The Senior Credit Facility also required
Brigham to maintain an interest coverage ratio for the four most recent quarters as of December 31,
2010 of at least 2.5 to 1. The Senior Credit Facility also required Brigham to maintain a net
leverage ratio for the quarters ending December 31, 2010 and March 31, 2011 not greater than 4.25
to 1, and thereafter not greater than 4.0 to 1. At December 31, 2010, Brigham was in compliance
with all covenants under the Senior Credit Facility.
Subsequent to December 31, 2010, Brigham amended and restated its Senior Credit Facility to
provide for revolving credit borrowings up to $600 million, with an initial borrowing base of $325
million. Borrowings under the new Senior Credit Facility cannot exceed its borrowing base, which
is determined at least semi-annually. Brigham also extended the maturity of its Senior Credit
Facility from July 2012 to February 2016. As part of the new Senior Credit Facility, the
requirement to maintain a minimum interest coverage ratio was removed. See Note 16 Subsequent
Events.
Senior Notes
On September 27, 2010, Brigham issued $300 million of 8 3/4% Senior Notes due October 2018
(collectively the 8 3/4% Senior Notes). The notes were priced at 100% of their face value and are
fully and unconditionally guaranteed by Brigham and its wholly-owned subsidiaries, Brigham, Inc.
and Brigham Oil & Gas, L.P. Brigham does not have any independent assets or operations.
F-14
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In connection with the issuance of the 8 3/4% Senior Notes, Brigham tendered for and purchased
$154.4 million of its 9 5/8% Senior Notes due 2014 and previously issued in 2006 and 2007 on
September 27, 2010. Brigham recorded a $10.9 million loss upon the purchase of the 9 5/8% Senior
Notes. Brigham redeemed the remaining $5.6 million of the 9 5/8% Senior Notes on October 8, 2010.
Brigham recorded a $360,000 loss upon the redemption of the remaining 9 5/8% Senior Notes.
The indenture governing the 8 3/4% Senior Notes contains customary events of default. Upon the
occurrence of certain events of default, the trustee or the holders of the 8 3/4% Senior Notes may
declare all outstanding 8 3/4% Senior Notes to be due and payable immediately. The indenture also
contains customary restrictions and covenants which could potentially limit Brighams flexibility
to manage and fund its business. At December 31, 2010, Brigham was in compliance with all
covenants under the indenture.
6. Preferred Stock
Series A Mandatorily Redeemable Preferred Stock
The following table reflects the outstanding shares of Series A mandatorily redeemable
preferred stock and the activity related thereto for the years ended December 31, 2010 and 2009 (in
thousands, except share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
Year Ended |
|
|
|
December 31, 2010 |
|
|
December 31, 2009 |
|
|
|
Shares |
|
|
Amounts |
|
|
Shares |
|
|
Amounts |
|
Balance, beginning of year |
|
|
505,051 |
|
|
$ |
10,101 |
|
|
|
505,051 |
|
|
$ |
10,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
|
|
|
|
$ |
|
|
|
|
505,051 |
|
|
$ |
10,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brigham had designated 2,250,000 shares of preferred stock as Series A Preferred Stock. The
Series A Preferred Stock had a par value of $0.01 per share and a stated value of $20 per share.
The Series A Preferred Stock was cumulative and paid dividends quarterly at a rate of 6% per annum
of the stated value in cash. The Series A Preferred Stock was set to mature on October 31, 2010 and
was redeemable at Brighams option at 100% or 101% of stated value (depending upon certain
conditions) at anytime prior to maturity. The Series A Preferred Stock did not generally have any
voting rights, except for certain approval rights and as required by law.
In June 2010, Brigham exercised its option to redeem all of its Series A mandatorily
redeemable preferred stock at 101% of the stated value per share, which was held by DLJ Merchant
Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse
Securities (USA), LLC.
7. Asset Retirement Obligations
Brigham has asset retirement obligations associated with the future plugging and abandonment
of proved properties and related facilities. Prior to the adoption of Financial Accounting
Standards Board Accounting Standards Codification Topic 410 Asset Retirement and Environmental
Obligations (FASB ASC 410), Brigham assumed salvage value approximated plugging and abandonment
costs. As such, estimated salvage value was not excluded from depletion and plugging and
abandonment costs were not accrued for over the life of the oil and gas properties. Under the
provisions of FASB ASC 410, the fair value of a liability for an asset retirement obligation is
recorded in the period in which it is incurred and a corresponding increase in the carrying amount
of the related long-lived asset. The liability is accreted to its present value each period, and
the capitalized cost is depreciated over the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, a gain or loss is recognized. Brigham has no
assets that are legally restricted for purposes of settling asset retirement obligations.
F-15
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table summarizes Brighams asset retirement obligation transactions recorded in
accordance with the provisions of FASB ASC 410 during the years ended December 31, 2010 and 2009
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Beginning asset retirement obligations |
|
$ |
6,323 |
|
|
$ |
5,592 |
|
Liabilities incurred for new wells placed on production |
|
|
814 |
|
|
|
327 |
|
Liabilities settled |
|
|
(428 |
) |
|
|
(17 |
) |
Revisions to estimates due to sale of oil and gas properties |
|
|
(1,208 |
) |
|
|
|
|
Accretion of discount on asset retirement obligations |
|
|
422 |
|
|
|
421 |
|
|
|
|
|
|
|
|
|
|
$ |
5,923 |
|
|
$ |
6,323 |
|
|
|
|
|
|
|
|
8. Income Taxes
Brigham utilizes the asset and liability approach to measure deferred tax assets and
liabilities based on temporary differences existing at each balance sheet date using currently
enacted tax rates in accordance with Financial Accounting Standards Board Accounting Standards
Codification Topic 740 Income Taxes (FASB ASC 740). Deferred tax assets and liabilities are
adjusted for the effects of changes in tax laws and rates on the date of enactment. Under FASB ASC
740, deferred tax assets are reduced by a valuation allowance when, in the opinion of management,
it is more likely than not that some portion or all of the deferred tax assets will not be
realized. During 2009, Brighams deferred tax asset relating to oil and gas properties was
increased primarily due to Brighams ceiling test writedown in the first quarter of 2009. During
2010, Brighams deferred tax asset decreased for federal and state purposes. After testing to
determine if the deferred tax assets would meet the more likely than not criteria, Brigham
decreased its federal valuation allowance to $62.3 million and its state valuation allowance to
$5.2 million.
The total provision for income taxes consists of the following (dollar amounts are in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Current income taxes |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Deferred income taxes (benefits): |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
14,805 |
|
|
|
(43,029 |
) |
|
|
(71,445 |
) |
State |
|
|
1,655 |
|
|
|
(1,141 |
) |
|
|
(5,745 |
) |
Federal and state valuation allowances |
|
|
(15,376 |
) |
|
|
43,937 |
|
|
|
34,489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,084 |
|
|
$ |
(233 |
) |
|
$ |
(42,701 |
) |
|
|
|
|
|
|
|
|
|
|
The provision for income taxes differs from the amount computed by applying the statutory
federal income tax rate to net income before taxes. The sources of the tax effects of the
differences are as follows (dollar amounts are in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Tax (benefit) at statutory rate |
|
$ |
15,393 |
|
|
$ |
(43,129 |
) |
|
$ |
(71,732 |
) |
Add the effect of: |
|
|
|
|
|
|
|
|
|
|
|
|
Nondeductible expenses, net of tax exempt income |
|
|
7 |
|
|
|
1 |
|
|
|
6 |
|
Preferred stock dividends |
|
|
129 |
|
|
|
212 |
|
|
|
212 |
|
Incentive stock options not exercised |
|
|
93 |
|
|
|
26 |
|
|
|
47 |
|
State income taxes (benefits), net of federal deduction |
|
|
1,076 |
|
|
|
(741 |
) |
|
|
(3,734 |
) |
State valuation allowance, net of federal deduction |
|
|
(369 |
) |
|
|
644 |
|
|
|
2,455 |
|
Federal valuation allowance |
|
|
(15,303 |
) |
|
|
42,719 |
|
|
|
30,002 |
|
Other |
|
|
58 |
|
|
|
35 |
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,084 |
|
|
$ |
(233 |
) |
|
$ |
(42,701 |
) |
|
|
|
|
|
|
|
|
|
|
F-16
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The components of deferred income tax assets and liabilities are as follows (dollar amounts
are in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Deferred tax assets |
|
|
|
|
|
|
|
|
Current: |
|
|
|
|
|
|
|
|
Unrealized hedging and other derivative losses |
|
$ |
3,504 |
|
|
$ |
913 |
|
State deferred taxes |
|
|
381 |
|
|
|
|
|
Other |
|
|
82 |
|
|
|
36 |
|
|
|
|
|
|
|
|
Current |
|
|
3,967 |
|
|
|
949 |
|
|
|
|
|
|
|
|
Non-current: |
|
|
|
|
|
|
|
|
Net operating loss carryforwards (NOLs) |
|
|
82,394 |
|
|
|
84,706 |
|
Percentage depletion carryforwards |
|
|
4,896 |
|
|
|
4,433 |
|
Stock compensation |
|
|
4,115 |
|
|
|
3,328 |
|
Asset retirement obligations |
|
|
2,073 |
|
|
|
2,213 |
|
Unrealized derivative losses |
|
|
3,100 |
|
|
|
318 |
|
Other |
|
|
784 |
|
|
|
81 |
|
|
|
|
|
|
|
|
Non-current |
|
|
97,362 |
|
|
|
95,079 |
|
|
|
|
|
|
|
|
|
|
|
101,329 |
|
|
|
96,028 |
|
Valuation allowance |
|
|
(62,309 |
) |
|
|
(77,153 |
) |
|
|
|
|
|
|
|
Total net deferred tax assets |
|
|
39,020 |
|
|
|
18,875 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities |
|
|
|
|
|
|
|
|
Current: |
|
|
|
|
|
|
|
|
Unrealized derivative gains |
|
$ |
(1,630 |
) |
|
$ |
(403 |
) |
|
|
|
|
|
|
|
Current |
|
|
(1,630 |
) |
|
|
(403 |
) |
|
|
|
|
|
|
|
Non-current: |
|
|
|
|
|
|
|
|
Depreciable and depletable property |
|
|
(36,851 |
) |
|
|
(18,392 |
) |
Other |
|
|
(539 |
) |
|
|
(80 |
) |
|
|
|
|
|
|
|
Non-current |
|
|
(37,390 |
) |
|
|
(18,472 |
) |
|
|
|
|
|
|
|
Total net deferred tax liabilities |
|
|
(39,020 |
) |
|
|
(18,875 |
) |
|
|
|
|
|
|
|
Total federal deferred tax asset (liability) |
|
|
|
|
|
|
|
|
Total state deferred tax asset (liability) |
|
|
(1,088 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax asset (liability) |
|
$ |
(1,088 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
At December 31, 2010, Brigham has regular U. S. Federal tax NOLs of approximately $249 million
available as a deduction against future taxable income. Additionally, Brigham has approximately
$234 million of U. S. Federal alternative minimum tax (AMT) NOLs. The NOLs expire from 2012
through 2029. The value of these NOLs depends on the ability of Brigham to generate taxable income.
Brigham also has U. S. State tax NOLs of approximately $93.7 million (of which $19.5 million
relates to the Williston Basin) and a Texas Franchise tax credit carryover of approximately $1.4
million. The decreases in the valuation allowances have no impact on Brighams NOL positions for
federal and state tax purposes.
Brigham believes an Internal Revenue Code Sec. 382 ownership change may have occurred in March
2001 and in November 2005, as a result of a potential 50% change in ownership among its 5%
shareholders over a three-year period. Limitations on the utilization of Brighams NOLs may result
from the March 2001 and November 2005 ownership changes. The limitations approximate $5.2 million
annually and $22 million annually, respectively.
On January 1, 2007, Brigham adopted additional provisions under FASB ASC 740, which provides
that the tax effects from an uncertain tax position can be recognized in the financial statements
only if the position is more likely than not of being sustained if the position were to be
challenged by a taxing authority. In 2006 and 2007, Brigham examined the tax positions taken in its
tax returns and determined that the full values of the uncertain tax positions were reflected as
part of its deferred tax liabilities and reclassified these liabilities to other tax liabilities on
the consolidated balance sheet. In 2008, Brigham received approval from the Internal Revenue
Service to change its method of accounting for certain geological and geophysical costs and no
longer has a liability for uncertain tax positions. As a result, as of December 31, 2008, Brigham
eliminated the other tax liabilities in its consolidated balance sheet.
F-17
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The tax years that remain subject to examination by Federal and major state tax jurisdictions
are the years ended December 31, 2010, 2009, 2008, and 2007. In addition, Brigham is open to
examination for the years 1997 through 2006, resulting from NOLs generated and available for
carryforward.
9. Net Income Available Per Common Share
Basic earnings per share are computed by dividing net income (loss) available to common
stockholders by the weighted average number of common shares outstanding for the period. Diluted
EPS is computed by dividing net income by the weighted average number of common shares and
potential common shares outstanding (if dilutive) during each period. Potential common shares
include stock options and restricted stock. The number of potential common shares outstanding
relating to stock options and restricted stock is computed using the treasury stock method.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands, except per share amounts) |
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders |
|
$ |
42,896 |
|
|
$ |
(122,992 |
) |
|
$ |
(162,247 |
) |
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding basic |
|
|
111,355 |
|
|
|
70,569 |
|
|
|
45,441 |
|
|
|
|
|
|
|
|
|
|
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders |
|
$ |
0.39 |
|
|
$ |
(1.74 |
) |
|
$ |
(3.57 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders diluted |
|
$ |
42,896 |
|
|
$ |
(122,992 |
) |
|
$ |
(162,247 |
) |
|
|
|
|
|
|
|
|
|
|
Common shares outstanding |
|
|
111,355 |
|
|
|
70,569 |
|
|
|
45,441 |
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and restricted stock |
|
|
1,953 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potentially dilutive common shares |
|
|
1,953 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted common shares outstanding diluted |
|
|
113,308 |
|
|
|
70,569 |
|
|
|
45,441 |
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders |
|
$ |
0.38 |
|
|
$ |
(1.74 |
) |
|
$ |
(3.57 |
) |
|
|
|
|
|
|
|
|
|
|
At December 31, 2010, 2009, and 2008, potential dilution of approximately 1.0 million, 4.7
million, and 3.7 million shares of common stock, respectively, related to mandatorily redeemable
preferred stock and options were outstanding, but were not included in the computation of diluted
income (loss) per share because the effect of these instruments would have been anti-dilutive.
10. Contingencies, Commitments and Factors Which May Affect Future Operations
Litigation
Brigham is, from time to time, party to certain lawsuits and claims arising in the ordinary
course of business. While the outcome of lawsuits and claims cannot be predicted with certainty and
Brigham is unable to estimate a range of possible loss, management does not expect these matters to
have a materially adverse effect on the financial condition, results of operations or cash flows of
Brigham.
As of December 31, 2010, there are no known environmental or other regulatory matters related
to Brighams operations that are reasonably expected to result in a material liability to Brigham.
Compliance with environmental laws and regulations has not had, and is not expected to have, a
material adverse effect on Brighams financial position, results of operations or cash flows.
F-18
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Operating Lease Commitments
Brigham leases office equipment and space
under operating leases expiring at various dates. The noncancelable term of the leases for Brighams office space expires
in 2012. Brigham is subject to early termination fees for four drilling rigs under a contract that is quarter-to-quarter
through May 2011. Brigham is also subject to early termination fees for each day remaining under the primary term for
five drilling rigs with renewable terms of a maximum of six months. Additionally, Brigham is subject to early termination
fees for each day remaining under the primary term for one drilling rig with a renewable quarterly term. Finally, Brigham
is subject to early termination fees for each day remaining under the contract for two walking rigs. Both of these contracts
contain three year terms and begin once Brigham receives the rigs. The future minimum annual rental payments under the
noncancelable terms of these leases and potential fees for early termination of the drilling rig contracts at December 31,
2010 are as follows (in thousands):
|
|
|
|
|
2011
|
|
|
10,225 |
|
2012
|
|
|
11,191 |
|
2013
|
|
|
10,950 |
|
2014
|
|
|
10,950 |
|
2015
|
|
|
465 |
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
$ |
43,781 |
|
|
|
|
|
Rental expense for the years ended December 31, 2010, 2009 and 2008 was approximately $789,000,
$804,000, and $770,000, respectively.
Major Purchasers
The following purchasers accounted for 10% or more of Brighams oil and natural gas sales for
the years ended December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Purchaser A |
|
|
|
|
|
|
|
|
|
|
21 |
% |
Purchaser B |
|
|
|
|
|
|
31 |
% |
|
|
19 |
% |
Purchaser C |
|
|
17 |
% |
|
|
13 |
% |
|
|
|
|
Purchaser D |
|
|
19 |
% |
|
|
|
|
|
|
|
|
Purchaser E |
|
|
18 |
% |
|
|
|
|
|
|
|
|
Purchaser F |
|
|
13 |
% |
|
|
|
|
|
|
|
|
Brigham believes that the loss of any individual purchaser would not have a long-term material
adverse impact on its financial position or results of operations.
Factors Which May Affect Future Operations
Since Brighams major products are commodities, significant changes in the prices of oil and
natural gas could have a significant impact on Brighams results of operations for any particular
year.
11. Derivative Instruments and Hedging Activities
Brigham utilizes various commodity swap and option contracts to (i) reduce the effects of
volatility in price changes on the oil and natural gas commodities it produces and sells, (ii)
reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can
execute at least a portion of its capital spending plans.
Natural Gas and Crude Oil Derivative Contracts
Cash flow hedges
Brigham enters into contracts to hedge against the variability in cash flows associated with
the forecasted sale of future oil and gas production. Brighams hedges consist of costless collars
(purchased put options and written call options), three-way collars (a standard collar plus a sold
put below the floor price of the collar), purchased put options, written call options, and swaps.
The costless collars and three-way collars are used to establish floor and ceiling prices on
anticipated future oil and natural gas production. There are no net premiums paid or received when
Brigham enters into these option agreements. Brigham has elected not to designate any of its
derivative contracts as cash flow hedges for accounting purposes under Financial Accounting
Standards Board Accounting Standards Codification Topic 815 Derivatives and Hedging (FASB ASC
815). As such, all derivative positions are carried at their fair value on the consolidated balance
sheet and are marked-to-market at the end of each period. See Note 12, Fair Values, for a
discussion of the calculation of the fair values of oil and natural gas derivative contracts. Any
realized and unrealized gains or losses are recorded as gain (loss) on derivatives, net, as an
increase or decrease in revenue on the consolidated statement of operations.
F-19
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following tables reflect Brighams open commodity derivative contracts at December 31,
2010, the associated volumes and the corresponding weighted average NYMEX reference price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
|
|
|
|
Purchased |
|
|
Written |
|
|
|
Gas |
|
|
Oil |
|
|
Put |
|
|
Call |
|
Settlement Period |
|
(MMBTU) |
|
|
(Barrels) |
|
|
Nymex |
|
|
Nymex |
|
Natural Gas Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
01/01/11 03/31/11 |
|
|
120,000 |
|
|
|
|
|
|
$ |
6.50 |
|
|
$ |
8.25 |
|
01/01/11 03/31/11 |
|
|
210,000 |
|
|
|
|
|
|
$ |
6.40 |
|
|
$ |
7.80 |
|
01/01/11 12/31/11 |
|
|
360,000 |
|
|
|
|
|
|
$ |
5.75 |
|
|
$ |
7.65 |
|
01/01/11 12/31/11 |
|
|
480,000 |
|
|
|
|
|
|
$ |
5.75 |
|
|
$ |
7.40 |
|
04/01/11 12/31/11 |
|
|
360,000 |
|
|
|
|
|
|
$ |
5.00 |
|
|
$ |
6.55 |
|
Oil Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
01/01/11 07/31/12 |
|
|
|
|
|
|
289,000 |
|
|
$ |
65.00 |
|
|
$ |
97.20 |
|
01/01/11 07/31/12 |
|
|
|
|
|
|
289,000 |
|
|
$ |
65.00 |
|
|
$ |
98.55 |
|
01/01/11 07/31/12 |
|
|
|
|
|
|
289,000 |
|
|
$ |
65.00 |
|
|
$ |
100.40 |
|
01/01/11 07/31/12 |
|
|
|
|
|
|
289,000 |
|
|
$ |
65.00 |
|
|
$ |
100.00 |
|
01/01/11 02/28/11 |
|
|
|
|
|
|
29,500 |
|
|
$ |
65.00 |
|
|
$ |
98.75 |
|
01/01/11 02/28/11 |
|
|
|
|
|
|
10,000 |
|
|
$ |
70.00 |
|
|
$ |
92.00 |
|
01/01/11 02/28/11 |
|
|
|
|
|
|
8,000 |
|
|
$ |
75.00 |
|
|
$ |
103.50 |
|
01/01/11 03/31/11 |
|
|
|
|
|
|
9,000 |
|
|
$ |
75.00 |
|
|
$ |
93.50 |
|
01/01/11 06/30/11 |
|
|
|
|
|
|
18,000 |
|
|
$ |
65.00 |
|
|
$ |
97.50 |
|
01/01/11 06/30/11 |
|
|
|
|
|
|
24,000 |
|
|
$ |
70.00 |
|
|
$ |
92.50 |
|
01/01/11 07/31/11 |
|
|
|
|
|
|
21,000 |
|
|
$ |
70.00 |
|
|
$ |
94.80 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
84,000 |
|
|
$ |
65.00 |
|
|
$ |
88.25 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
60,000 |
|
|
$ |
60.00 |
|
|
$ |
97.25 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
60,000 |
|
|
$ |
65.00 |
|
|
$ |
108.00 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
48,000 |
|
|
$ |
70.00 |
|
|
$ |
106.80 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
48,000 |
|
|
$ |
75.00 |
|
|
$ |
102.60 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
36,000 |
|
|
$ |
65.00 |
|
|
$ |
100.00 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
36,000 |
|
|
$ |
75.00 |
|
|
$ |
104.30 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
182,500 |
|
|
$ |
65.00 |
|
|
$ |
100.00 |
|
03/01/11 04/30/11 |
|
|
|
|
|
|
16,000 |
|
|
$ |
75.00 |
|
|
$ |
104.50 |
|
03/01/11 08/31/11 |
|
|
|
|
|
|
46,000 |
|
|
$ |
65.00 |
|
|
$ |
96.75 |
|
03/01/11 08/31/11 |
|
|
|
|
|
|
46,000 |
|
|
$ |
65.00 |
|
|
$ |
94.80 |
|
05/01/11 12/31/11 |
|
|
|
|
|
|
122,500 |
|
|
$ |
65.00 |
|
|
$ |
100.00 |
|
05/01/11 12/31/11 |
|
|
|
|
|
|
122,500 |
|
|
$ |
65.00 |
|
|
$ |
106.50 |
|
07/01/11 09/30/11 |
|
|
|
|
|
|
9,000 |
|
|
$ |
70.00 |
|
|
$ |
95.00 |
|
07/01/11 12/31/11 |
|
|
|
|
|
|
12,000 |
|
|
$ |
75.00 |
|
|
$ |
103.00 |
|
07/01/11 12/31/11 |
|
|
|
|
|
|
12,000 |
|
|
$ |
75.00 |
|
|
$ |
95.15 |
|
09/01/11 12/31/11 |
|
|
|
|
|
|
61,000 |
|
|
$ |
65.00 |
|
|
$ |
99.00 |
|
09/01/11 12/31/11 |
|
|
|
|
|
|
61,000 |
|
|
$ |
65.00 |
|
|
$ |
97.40 |
|
10/01/11 12/31/11 |
|
|
|
|
|
|
6,000 |
|
|
$ |
70.00 |
|
|
$ |
96.35 |
|
01/01/12 06/30/12 |
|
|
|
|
|
|
60,000 |
|
|
$ |
75.00 |
|
|
$ |
106.90 |
|
01/01/12 06/30/12 |
|
|
|
|
|
|
182,000 |
|
|
$ |
65.00 |
|
|
$ |
100.75 |
|
01/01/12 06/30/12 |
|
|
|
|
|
|
91,000 |
|
|
$ |
65.00 |
|
|
$ |
101.00 |
|
01/01/12 06/30/12 |
|
|
|
|
|
|
182,000 |
|
|
$ |
65.00 |
|
|
$ |
99.25 |
|
01/01/12 06/30/12 |
|
|
|
|
|
|
91,000 |
|
|
$ |
65.00 |
|
|
$ |
102.75 |
|
01/01/12 06/30/12 |
|
|
|
|
|
|
136,500 |
|
|
$ |
65.00 |
|
|
$ |
107.25 |
|
01/01/12 07/31/12 |
|
|
|
|
|
|
106,500 |
|
|
$ |
65.00 |
|
|
$ |
110.00 |
|
07/01/12 07/31/12 |
|
|
|
|
|
|
62,000 |
|
|
$ |
65.00 |
|
|
$ |
102.25 |
|
07/01/12 07/31/12 |
|
|
|
|
|
|
31,000 |
|
|
$ |
65.00 |
|
|
$ |
105.25 |
|
07/01/12 09/30/12 |
|
|
|
|
|
|
92,000 |
|
|
$ |
65.00 |
|
|
$ |
109.40 |
|
08/01/12 09/30/12 |
|
|
|
|
|
|
61,000 |
|
|
$ |
65.00 |
|
|
$ |
110.25 |
|
08/01/12 09/30/12 |
|
|
|
|
|
|
61,000 |
|
|
$ |
65.00 |
|
|
$ |
112.00 |
|
08/01/12 10/31/12 |
|
|
|
|
|
|
92,000 |
|
|
$ |
70.00 |
|
|
$ |
110.90 |
|
08/01/12 10/31/12 |
|
|
|
|
|
|
92,000 |
|
|
$ |
70.00 |
|
|
$ |
106.50 |
|
10/01/12 10/31/12 |
|
|
|
|
|
|
62,000 |
|
|
$ |
65.00 |
|
|
$ |
112.65 |
|
10/01/12 10/31/12 |
|
|
|
|
|
|
31,000 |
|
|
$ |
70.00 |
|
|
$ |
110.90 |
|
11/01/12 12/31/12 |
|
|
|
|
|
|
122,000 |
|
|
$ |
70.00 |
|
|
$ |
107.70 |
|
11/01/12 12/31/12 |
|
|
|
|
|
|
122,000 |
|
|
$ |
70.00 |
|
|
$ |
110.00 |
|
F-20
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
|
|
|
|
Purchased |
|
|
Written |
|
|
|
Gas |
|
|
Oil |
|
|
Put |
|
|
Call |
|
Settlement Period |
|
(MMBTU) |
|
|
(Barrels) |
|
|
Nymex |
|
|
Nymex |
|
Crude Oil Calls |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
01/01/11 06/30/11 |
|
|
|
|
|
|
90,500 |
|
|
|
|
|
|
$ |
95.00 |
|
01/01/11 06/30/11 |
|
|
|
|
|
|
90,500 |
|
|
|
|
|
|
$ |
97.50 |
|
Crude Oil Puts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
01/01/11 06/30/12 |
|
|
|
|
|
|
273,500 |
|
|
$ |
65.00 |
|
|
|
|
|
01/01/11 06/30/12 |
|
|
|
|
|
|
273,500 |
|
|
$ |
65.00 |
|
|
|
|
|
07/01/11 06/30/12 |
|
|
|
|
|
|
91,500 |
|
|
$ |
65.00 |
|
|
|
|
|
07/01/11 06/30/12 |
|
|
|
|
|
|
91,500 |
|
|
$ |
65.00 |
|
|
|
|
|
The following tables reflect commodity derivative contracts entered subsequent to December 31,
2010, the associated volumes and the corresponding weighted average NYMEX reference price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
|
|
|
|
Purchased |
|
|
Written |
|
|
|
Gas |
|
|
Oil |
|
|
Put |
|
|
Call |
|
Settlement Period |
|
(MMBTU) |
|
|
(Barrels) |
|
|
Nymex |
|
|
Nymex |
|
Oil Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
07/01/12 07/31/12 |
|
|
|
|
|
|
62,000 |
|
|
$ |
75.00 |
|
|
$ |
114.00 |
|
08/01/12 10/31/12 |
|
|
|
|
|
|
276,000 |
|
|
$ |
75.00 |
|
|
$ |
112.50 |
|
11/01/12 12/30/12 |
|
|
|
|
|
|
244,000 |
|
|
$ |
75.00 |
|
|
$ |
112.50 |
|
01/01/13 02/28/13 |
|
|
|
|
|
|
118,000 |
|
|
$ |
75.00 |
|
|
$ |
113.05 |
|
01/01/13 03/31/13 |
|
|
|
|
|
|
180,000 |
|
|
$ |
80.00 |
|
|
$ |
120.00 |
|
03/01/13 03/31/13 |
|
|
|
|
|
|
62,000 |
|
|
$ |
80.00 |
|
|
$ |
120.00 |
|
Crude Oil Calls |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
07/01/11 12/31/11 |
|
|
|
|
|
|
276,000 |
|
|
|
|
|
|
$ |
100.00 |
|
Crude Oil Puts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
07/01/12 12/31/12 |
|
|
|
|
|
|
276,000 |
|
|
$ |
80.00 |
|
|
|
|
|
Additional Disclosures about Derivative Instruments and Hedging Activities
At December 31, 2010 and 2009, Brigham had derivative financial instruments under FASB ASC 815
recorded on the consolidated balance sheet as set forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dec 31, 2010 |
|
|
Dec 31, 2009 |
|
|
|
|
|
Estimated |
|
|
Estimated |
|
Type of Contract |
|
Balance Sheet Location |
|
Fair Value |
|
|
Fair Value |
|
|
|
|
|
(in thousands) |
|
|
(in thousands) |
|
Derivatives Not Designated
as Hedging Instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
Natural gas and oil contracts |
|
Other current assets |
|
$ |
2,557 |
|
|
$ |
1,152 |
|
Natural gas and oil contracts |
|
Other non-current assets |
|
|
309 |
|
|
|
186 |
|
|
|
|
|
|
|
|
|
|
Total Derivative Assets |
|
|
|
$ |
2,866 |
|
|
$ |
1,338 |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
Natural gas and oil contracts |
|
Derivative liabilities current |
|
$ |
(9,442 |
) |
|
$ |
(2,405 |
) |
Natural gas and oil contracts |
|
Other non-current liabilities |
|
|
(8,575 |
) |
|
|
(909 |
) |
|
|
|
|
|
|
|
|
|
Total Derivative Liabilities |
|
|
|
$ |
(18,017 |
) |
|
$ |
(3,314 |
) |
F-21
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For the three years ended December 31, 2010 and 2009, the effect on income in the consolidated
statement of operations for derivative financial instruments under FASB ASC 815 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year |
|
|
Year |
|
|
|
|
|
Ended |
|
|
Ended |
|
|
|
|
|
Dec 31, 2010 |
|
|
Dec 31, 2009 |
|
|
|
Statement of Operations |
|
Amount of |
|
|
Amount of |
|
Type of Contract |
|
Location of Gain (Loss) |
|
Gain (Loss) |
|
|
Gain (Loss) |
|
|
|
|
|
(in thousands) |
|
|
(in thousands) |
|
Derivatives Not
Designated as Hedging
Instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas contracts |
|
Gain (loss) on derivatives, net |
|
$ |
4,210 |
|
|
$ |
7,061 |
|
Oil contracts |
|
Gain (loss) on derivatives, net |
|
|
(14,276 |
) |
|
|
(4,997 |
) |
|
|
|
|
|
|
|
|
|
|
Total Derivative Gain (loss) |
|
|
|
$ |
(10,066 |
) |
|
$ |
2,064 |
|
|
|
|
|
|
|
|
|
|
|
The use of derivative transactions involves the risk that the counterparties will be unable to
meet the financial terms of such transactions. Brighams derivative contracts are with multiple
counterparties to minimize its exposure to any individual counterparty and Brigham has netting
arrangements with all of its counterparties that provide for offsetting payables against
receivables from separate derivative instruments with that counterparty.
12. Fair Values
Brigham adopted Financial Accounting Standards Board Accounting Standards Codification Topic
820 Fair Value Measurements and Disclosures (FASB ASC 820) on January 1, 2008, as it relates to
financial assets and liabilities. Brigham adopted FASB ASC 820 on January 1, 2009, as it relates to
nonfinancial assets and liabilities. FASB ASC 820 establishes a fair value hierarchy that
prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy
defined by FASB ASC 820 are as follows:
|
|
|
Level 1 Unadjusted quoted prices are available in active markets for identical
assets or liabilities. |
|
|
|
Level 2 Pricing inputs, other than quoted prices within Level 1, that are either
directly or indirectly observable. |
|
|
|
Level 3 Pricing inputs that are unobservable requiring the use of valuation
methodologies that result in managements best estimate of fair value. |
F-22
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As such, the fair values of Brighams derivative financial instruments reflect Brighams
estimate of the default risk of the parties in accordance with FASB ASC 820. Brigham determines the
fair value of derivative financial instruments based on counterparties valuation models that
utilize market-corroborated inputs. The fair value of all derivative contracts is reflected on the
balance sheet as detailed in the following schedule. The current asset and liability amounts
represent the fair values expected to be included in the results of operations for the subsequent
year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2010 Using |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|
|
Active Markets |
|
|
Observable |
|
|
Unobservable |
|
|
|
December 31, |
|
|
for Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
Description |
|
2010 |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Current derivative liabilities |
|
$ |
(9,442 |
) |
|
$ |
|
|
|
$ |
(9,442 |
) |
|
$ |
|
|
Other non-current liabilities |
|
|
(8,575 |
) |
|
|
|
|
|
|
(8,575 |
) |
|
|
|
|
Other current assets |
|
|
2,557 |
|
|
|
|
|
|
|
2,557 |
|
|
|
|
|
Other non-current assets |
|
|
309 |
|
|
|
|
|
|
|
309 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(15,151 |
) |
|
$ |
|
|
|
$ |
(15,151 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2009 Using |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|
|
Active Markets |
|
|
Observable |
|
|
Unobservable |
|
|
|
December 31, |
|
|
for Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
Description |
|
2009 |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Current derivative liabilities |
|
$ |
(2,405 |
) |
|
$ |
|
|
|
$ |
(2,405 |
) |
|
$ |
|
|
Other non-current liabilities |
|
|
(909 |
) |
|
|
|
|
|
|
(909 |
) |
|
|
|
|
Current derivative assets |
|
|
1,152 |
|
|
|
|
|
|
|
1,152 |
|
|
|
|
|
Other non-current assets |
|
|
186 |
|
|
|
|
|
|
|
186 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1,976 |
) |
|
$ |
|
|
|
$ |
(1,976 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brighams assessment of the significance of a particular input to the fair value measurement
requires judgment and may effect the valuation of the nonfinancial assets and liabilities and their
placement in the fair value hierarchy levels. The fair value of Brighams asset retirement
obligations are determined using discounted cash flow methodologies based on inputs that are not
readily available in public markets. The fair value of the asset retirement obligations is
reflected on the balance sheet as detailed below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2010 Using |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|
|
Active Markets |
|
|
Observable |
|
|
Unobservable |
|
|
|
December 31, |
|
|
for Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
Description |
|
2010 |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Other non-current liabilities |
|
|
(5,923 |
) |
|
|
|
|
|
|
|
|
|
|
(5,923 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(5,923 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(5,923 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2009 Using |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|
|
Active Markets |
|
|
Observable |
|
|
Unobservable |
|
|
|
December 31, |
|
|
for Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
Description |
|
2009 |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Other non-current liabilities |
|
|
(6,323 |
) |
|
|
|
|
|
|
|
|
|
|
(6,323 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(6,323 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(6,323 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
F-23
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
See Note 7 for a rollforward of the asset retirement obligation.
As of December 31, 2010 and 2009, Brigham held $224.0 and $80.1 million, respectively, of
investments in certificates of deposit, corporate debt, and government securities. The fair value
of the investments is reflected on the balance sheet as detailed below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2010 Using |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|
|
Active Markets |
|
|
Observable |
|
|
Unobservable |
|
|
|
December 31, |
|
|
for Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
Description |
|
|
2010 |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Investments |
|
|
223,991 |
|
|
|
223,991 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
223,991 |
|
|
$ |
223,991 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2009 Using |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|
|
Active Markets |
|
|
Observable |
|
|
Unobservable |
|
|
|
December 31, |
|
|
for Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
Description |
|
2009 |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Investments |
|
|
80,093 |
|
|
|
80,093 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
80,093 |
|
|
$ |
80,093 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes, by major security type, the fair value and any unrealized gain
(loss) of Brighams investments. The unrealized gain (loss) is recorded on the consolidated balance
sheet as other comprehensive income (loss), a component of stockholders equity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less Than 12 Months |
|
|
12 Months or Greater |
|
|
Total |
|
|
|
|
|
|
|
Unrealized |
|
|
|
|
|
|
Unrealized |
|
|
|
|
|
|
Unrealized |
|
Description of |
|
Fair |
|
|
Gains |
|
|
Fair |
|
|
Gains |
|
|
Fair |
|
|
Gains |
|
Securities |
|
Value |
|
|
(Losses) |
|
|
Value |
|
|
(Losses) |
|
|
Value |
|
|
(Losses) |
|
Certificates of deposit |
|
$ |
241 |
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
241 |
|
|
$ |
1 |
|
Corporate debt |
|
|
183,391 |
|
|
|
68 |
|
|
|
26,324 |
|
|
|
(86 |
) |
|
|
209,715 |
|
|
|
(18 |
) |
Government securities |
|
|
14,035 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
14,035 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
197,667 |
|
|
$ |
77 |
|
|
$ |
26,324 |
|
|
$ |
(86 |
) |
|
$ |
223,991 |
|
|
$ |
(9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The cost basis of Brighams investments in certificates of deposit, corporate bonds and notes,
and government securities (in thousands) is $240, $212,464, and $14,103, respectively
Brighams other financial instruments include cash and cash equivalents, accounts receivable,
accounts payable and long-term debt. The carrying amount of cash and cash equivalents, accounts
receivable and accounts payable approximate fair value because of their immediate or short-term
maturities. The carrying value of Brighams senior credit facility approximates its fair market
value since it bears interest at floating market interest rates. The following are estimated fair
values and carrying values of our other financial instruments at each of these dates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010 |
|
|
December 31, 2009 |
|
|
|
(in millions) |
|
|
(in millions) |
|
|
|
Carrying |
|
|
Fair |
|
|
Carrying |
|
|
Fair |
|
|
|
Amount |
|
|
Value |
|
|
Amount |
|
|
Value |
|
Senior Notes |
|
$ |
300,000 |
|
|
$ |
325,500 |
|
|
$ |
160,000 |
|
|
$ |
160,000 |
|
Series A Preferred Stock |
|
$ |
|
|
|
$ |
|
|
|
$ |
10,101 |
|
|
$ |
10,166 |
|
The fair value of Brighams Senior Notes is based upon current market quotes and is the
estimated amount required to purchase the Senior Notes on the open market.
F-24
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Stock Based Compensation
Brigham applies Financial Accounting Standards Board Accounting Standards Codification Topic
718 Compensation Stock Compensation (FASB ASC 718) to account for stock based compensation.
The cost for all stock based awards is based on the grant date fair value estimated in accordance
with the provisions of FASB ASC 718 and is amortized on a straight-line basis over the requisite
service period including estimates of pre-vesting forfeiture rates. If actual forfeitures differ
from the estimates, additional adjustments to compensation expense may be required in future
periods. The maximum contractual life of stock based awards is ten years.
The estimated fair value of the options granted during the twelve months ended December 31,
2010, 2009, and 2008 was calculated using a Black-Scholes-Merton option pricing model
(Black-Scholes). The following table summarizes the weighted average assumptions used in the
Black-Scholes model for each of the three years ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Risk-free interest rate |
|
|
2.46 |
% |
|
|
2.64 |
% |
|
|
2.78 |
% |
Expected life (in years) |
|
|
5.0 |
|
|
|
5.0 |
|
|
|
5.0 |
|
Expected volatility |
|
|
81 |
% |
|
|
78 |
% |
|
|
56 |
% |
Expected dividend yield |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fair value per share of stock compensation |
|
$ |
12.38 |
|
|
$ |
3.41 |
|
|
$ |
2.52 |
|
The Black-Scholes model incorporates assumptions to value stock based awards. The risk-free
rate of interest for periods within the contractual life of the option is based on a zero-coupon
U.S. government instrument over the contractual term of the equity instrument. Expected volatility
is based on the historical volatility of Brighams stock for an equal period of the expected term.
Prior to the adoption of FASB ASC 718, Brigham presented all tax benefits of deductions
resulting from the exercise of stock options as operating cash flows in the Consolidated Statement
of Cash Flows. FASB ASC 718 requires the cash flow resulting from the tax deductions in excess of
the compensation cost recognized for those options (excess tax benefits) to be classified as
financing cash flows. Brigham did not record any excess tax benefits during the twelve months ended
December 31, 2010 and 2009.
The following table summarizes the components of stock based compensation included in general
and administrative expense (in thousands (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended |
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Pre-tax stock based compensation expense |
|
$ |
4,992 |
|
|
$ |
4,282 |
|
|
$ |
2,926 |
|
Capitalized stock based compensation |
|
|
(2,316 |
) |
|
|
(2,003 |
) |
|
|
(1,334 |
) |
Tax benefit |
|
|
(937 |
) |
|
|
(798 |
) |
|
|
(557 |
) |
|
|
|
|
|
|
|
|
|
|
Stock based compensation expense, net |
|
$ |
1,739 |
|
|
$ |
1,481 |
|
|
$ |
1,035 |
|
|
|
|
|
|
|
|
|
|
|
Brigham provides an incentive plan for the issuance of stock options, stock appreciation
rights, stock, restricted stock, cash or any combination of the foregoing. The objective of this
plan is to provide incentive and reward key employees whose performance may have a significant
impact on the success of Brigham. It is Brighams policy to use unissued shares of stock when stock
options are exercised. The number of shares available under the plan is equal to the lesser of
9,966,003 or 12% of the total number of shares of common stock outstanding. At December 31, 2010,
approximately 1,746,015 shares remain available for grant under the current incentive plan. The
Compensation Committee of the Board of Directors determines the type of awards made to each
participant and the terms, conditions and limitations applicable to each award. Except for one
series of stock option grants, options granted subsequent to March 4, 1997 have an exercise price
equal to the fair market value of Brighams common stock on the date of grant, vest over five years
and have a maximum contractual life of ten years.
Brigham also maintains a director stock option plan under which stock options are awarded to
non-employee directors. Options granted under this plan have an exercise price equal to the fair
market value of Brigham common stock on the date of grant and vest over five years. Stockholders
have authorized the issuance of 1,000,000 shares to non-employee directors and approximately
516,800 remain available for grant under the director stock option plan.
F-25
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table summarizes option activity under the incentive plans for each of the three
years ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
Average |
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Exercise |
|
|
|
|
|
|
Exercise |
|
|
|
|
|
|
Exercise |
|
|
|
Shares |
|
|
Price |
|
|
Shares |
|
|
Price |
|
|
Shares |
|
|
Price |
|
Options outstanding at
beginning of year |
|
|
4,170,137 |
|
|
$ |
5.14 |
|
|
|
3,128,651 |
|
|
$ |
7.00 |
|
|
|
3,046,166 |
|
|
$ |
7.14 |
|
Granted |
|
|
1,029,500 |
|
|
$ |
19.27 |
|
|
|
2,846,975 |
|
|
$ |
4.80 |
|
|
|
534,000 |
|
|
$ |
5.08 |
|
Forfeited or cancelled |
|
|
(22,200 |
) |
|
$ |
4.32 |
|
|
|
(1,549,675 |
) |
|
$ |
8.30 |
|
|
|
(65,300 |
) |
|
$ |
7.79 |
|
Exercised |
|
|
(741,037 |
) |
|
$ |
5.20 |
|
|
|
(255,814 |
) |
|
$ |
4.89 |
|
|
|
(386,215 |
) |
|
$ |
5.35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at
end of year |
|
|
4,436,400 |
|
|
$ |
8.41 |
|
|
|
4,170,137 |
|
|
$ |
5.14 |
|
|
|
3,128,651 |
|
|
$ |
7.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable at
end of year |
|
|
675,620 |
|
|
$ |
5.83 |
|
|
|
691,962 |
|
|
$ |
6.17 |
|
|
|
1,954,851 |
|
|
$ |
7.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average grant-date fair value of share options granted during the years ended
December 31, 2010, 2009, and 2008 was $12.38, $3.41, and $2.52, respectively. The total intrinsic
value of options exercised during the years ended December 31, 2010, 2009 and 2008 was $10.2 million,
$1.5 million, and $2.4 million, respectively.
The following table summarizes information about stock options outstanding at December 31,
2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
|
Options Exercisable |
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
Number |
|
|
Average |
|
|
Weighted- |
|
|
Number |
|
|
Average |
|
|
Weighted- |
|
|
|
Outstanding at |
|
|
Remaining |
|
|
Average |
|
|
Exercisable at |
|
|
Remaining |
|
|
Average |
|
|
|
December 31, |
|
|
Contractual |
|
|
Exercise |
|
|
December 31, |
|
|
Contractual |
|
|
Exercise |
|
Exercise Price |
|
2010 |
|
|
Life |
|
|
Price |
|
|
2010 |
|
|
Life |
|
|
Price |
|
$2.20 to $3.11 |
|
|
1,089,000 |
|
|
8.2 years |
|
|
$ |
2.24 |
|
|
|
137,000 |
|
|
8.1 years |
|
|
$ |
2.26 |
|
5.08 to 5.08 |
|
|
371,320 |
|
|
4.8 years |
|
|
$ |
5.08 |
|
|
|
101,320 |
|
|
4.8 years |
|
|
$ |
5.08 |
|
5.96 to 6.23 |
|
|
1,599,580 |
|
|
8.0 years |
|
|
$ |
5.98 |
|
|
|
301,300 |
|
|
6.7 years |
|
|
$ |
6.02 |
|
7.22 to 8.84 |
|
|
111,000 |
|
|
3.9 years |
|
|
$ |
7.52 |
|
|
|
42,000 |
|
|
3.5 years |
|
|
$ |
7.47 |
|
8.93 to 13.86 |
|
|
236,000 |
|
|
6.5 years |
|
|
$ |
11.66 |
|
|
|
94,000 |
|
|
3.0 years |
|
|
$ |
10.47 |
|
14.43 to 16.85 |
|
|
62,000 |
|
|
9.4 years |
|
|
$ |
15.24 |
|
|
|
|
|
|
|
|
|
|
$ |
|
|
18.36 to 27.15 |
|
|
967,500 |
|
|
9.3 years |
|
|
$ |
19.53 |
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.20 to 27.15 |
|
|
4,436,400 |
|
|
7.9 years |
|
|
$ |
8.41 |
|
|
|
675,620 |
|
|
6.0 years |
|
|
$ |
5.83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic value of options outstanding and exercisable at December 31, 2010 was
$83.5 million and $15.2 million, respectively. The aggregate intrinsic value represents the total
pre-tax value (the difference between Brighams closing stock price on the last trading day of 2010
and the exercise price, multiplied by the number of in-the-money options) that would have been
received by the option holders had all option holders exercised their options on December 31, 2010.
The amount of aggregate intrinsic value will change based on the fair market value of Brighams
stock.
Brigham commenced an exchange offer on July 13, 2009 pursuant to which eligible employees were
offered the opportunity to exchange outstanding stock options granted prior to April 21, 2009 for
new stock options. On Monday, August 10, 2009, pursuant to the exchange offer, eligible option
holders tendered, and Brigham accepted for cancellation, 1,536,975 eligible stock options. After
the cancellation of the options accepted by Brigham in the exchange offer, Brigham granted new
stock options with an exercise price of $5.955 per share, which was the mean of the high and low
sales price per share of Brigham shares as reported by The Nasdaq Global Select Market on August
10, 2009. The exchange of options resulted in incremental compensation expense of $1.3 million that
is being recognized over the five year vesting period of the new options.
F-26
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2010 there was approximately $15.6 million of total unrecognized
compensation expense related to unvested stock based compensation plans. This compensation expense
is expected to be realized over the remaining vesting period of approximately 4.8 years.
Restricted Stock
During the year ended December 31, 2010, Brigham issued 105,363, restricted shares of common
stock as compensation to officers and employees of Brigham. Restrictions lapsed on 20,363 of these
shares in 2010, resulting in recognition of approximately $334,000 in compensation expense.
Restrictions on 85,000 restricted shares lapse in 2015. As of December 31, 2010, there was
approximately $2 million of total unrecognized compensation expense related to unvested restricted
stock. This compensation expense is expected to be recognized, net of forfeitures, over the
remaining vesting period of approximately 4 years. Brigham has assumed a 3% weighted average
forfeiture rate for restricted stock to be used in calculating compensation expense. If actual
forfeitures differ from the estimates, adjustments to compensation expense may be required in
future periods.
The following table reflects the outstanding restricted stock awards and activity related
thereto for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
Year Ended |
|
|
|
December 31, 2010 |
|
|
December 31, 2009 |
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
Weighted- |
|
|
|
Number of |
|
|
Average |
|
|
Number of |
|
|
Average |
|
|
|
Shares |
|
|
Price |
|
|
Shares |
|
|
Price |
|
Restricted Stock Awards: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted shares outstanding at the beginning of
the year |
|
|
556,990 |
|
|
$ |
7.04 |
|
|
|
593,260 |
|
|
$ |
7.58 |
|
Shares granted |
|
|
105,363 |
|
|
$ |
14.45 |
|
|
|
342,574 |
|
|
$ |
4.99 |
|
Lapse of restrictions |
|
|
(130,070 |
) |
|
$ |
7.71 |
|
|
|
(377,844 |
) |
|
$ |
6.02 |
|
Forfeitures |
|
|
(1,400 |
) |
|
$ |
5.26 |
|
|
|
(1,000 |
) |
|
$ |
9.49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted shares outstanding at the end of the year |
|
|
530,883 |
|
|
$ |
8.35 |
|
|
|
556,990 |
|
|
$ |
7.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14. Employee Benefit Plans
Brigham has adopted a defined contribution 401(k) plan for substantially all of its employees.
The plan provides for Brigham matching of employee contributions to the plan, at Brighams
discretion. During 2010, 2009, and 2008, Brigham provided a base match equal to 25% of eligible
employee contributions. Based on attainment of performance goals established at the beginning of
each fiscal year, Brigham matched an additional 200% of eligible employee contributions made during
2010. There was no additional match for employee contributions made during 2009 and 2008. Brigham
contributed approximately $1.7 million, $143,000, and $159,000 to the 401(k) plan for the years
ended December 31, 2010, 2009 and 2008, respectively, to match eligible contributions by employees.
15. Related Party Transactions
During the years ended December 31, 2010, 2009 and 2008, Brigham incurred costs of
approximately $9.7 million, $2.3 million, and $7.3 million, respectively, in fees for land
acquisition services performed by Brigham Land Management, owned by a brother of Brighams
Chairman, President and Chief Executive Officer and its Executive Vice President Land and
Administration. Other participants in Brighams 3-D seismic projects reimbursed Brigham for a
portion of these amounts. At December 31, 2010, 2009 and 2008, Brigham had a liability recorded in
accounts payable of approximately $1,000, $30,000, and $129,000, respectively, related to services
performed by this company.
Mr. Harold Carter, a director of Brigham, served as a consultant to Brigham on various aspects
of its business and strategic issues during 2008. Fees paid for these services by Brigham were
approximately $30,000 for the year ended December 31, 2008. During each of the years ended December
31, 2009 and 2008, additional payments of approximately $2,500 and $12,000, respectively, were made
for the reimbursement of certain expenses. At December 31, 2010, 2009 and 2008, there were no
payables related to these services recorded by Brigham.
F-27
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
From time to time, in the normal course of business, Brigham has engaged a service company in
which Mr. Hobart Smith, one of Brighams current directors, owns stock and serves as a consultant.
Total payments to the service company during 2010, 2009 and 2008 were $2 million, $420,000, and
$1.1 million, respectively. At December 31, 2010, 2009 and 2008, Brigham owed the service company
approximately $219,000, $102,000, and $76,000, respectively.
During the year ended
December 31, 2010, Brigham incurred costs of $68,000 for design and
development services related to the Brigham regional office located in
Williston, North Dakota. The
services are being provided by Decker Design & Development PC. The owner is married to a
sister of
Brighams Chairman, President and Chief Executive Officer and its Executive Vice President
Land
and Administration. At December 31, 2010, Brigham had a liability recorded in accounts
payable of
approximately $3,000 related to the services provided by this company.
16. Subsequent Events
During February 2011, Brigham amended and restated its Senior Credit Facility to provide for
revolving credit borrowings up to $600 million, with an initial borrowing base of $325 million.
Borrowings under the new Senior Credit Facility cannot exceed its borrowing base, which is
determined at least semi-annually. Brigham also extended the maturity of its new Senior Credit
Facility from July 2012 to February 2016.
17. Supplemental Cash Flow Information
Supplemental cash flow information consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Cash paid for interest, net of capitalized amounts |
|
$ |
4,726 |
|
|
$ |
14,545 |
|
|
$ |
12,382 |
|
Noncash investing and financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized asset retirement obligations |
|
|
814 |
|
|
|
327 |
|
|
|
412 |
|
Accrued drilling costs |
|
|
45,569 |
|
|
|
(4,270 |
) |
|
|
4,927 |
|
Capitalized stock compensation |
|
|
2,316 |
|
|
|
2,003 |
|
|
|
1,334 |
|
18. Other Assets and Liabilities
Other current assets consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
|
2010 |
|
|
2009 |
|
Prepayments |
|
$ |
2,490 |
|
|
$ |
767 |
|
Derivative assets |
|
|
2,557 |
|
|
|
1,152 |
|
Other |
|
|
2,749 |
|
|
|
365 |
|
|
|
|
|
|
|
|
|
|
$ |
7,796 |
|
|
$ |
2,284 |
|
|
|
|
|
|
|
|
Other current liabilities consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
|
2010 |
|
|
2009 |
|
Accrued interest |
|
$ |
6,971 |
|
|
$ |
2,660 |
|
Other accrued liabilities |
|
|
3,850 |
|
|
|
2,641 |
|
|
|
|
|
|
|
|
|
|
$ |
10,821 |
|
|
$ |
5,301 |
|
|
|
|
|
|
|
|
F-28
BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Natural Gas Exploration and Production Activities
Oil and natural gas sales reflect the market prices of net production sold or transferred with
appropriate adjustments for royalties, net profits interest and other contractual provisions. Lease
operating expenses include lifting costs incurred to operate and maintain productive wells and
related equipment including such costs as operating labor, repairs and maintenance, materials,
supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of
oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration
and development activities. Results of operations do not include interest expense and general
corporate amounts.
Costs Incurred and Capitalized Costs
The costs incurred in oil and natural gas acquisition, exploration and development activities
follow (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Costs incurred for the year: |
|
|
|
|
|
|
|
|
|
|
|
|
Exploration (including geological and geophysical costs) |
|
$ |
20,906 |
|
|
$ |
10,566 |
|
|
$ |
43,229 |
|
Property acquisition |
|
|
121,058 |
|
|
|
15,416 |
|
|
|
35,299 |
|
Development |
|
|
273,158 |
|
|
|
54,261 |
|
|
|
110,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
415,122 |
|
|
$ |
80,243 |
|
|
$ |
188,683 |
|
|
|
|
|
|
|
|
|
|
|
Excluded costs for prospects are accumulated by year. Costs are reflected in the full cost
pool as the drilling program is executed or as costs are evaluated and deemed impaired. Brigham
anticipates these excluded costs will be included in the depletion computation over the next five
years. Brigham is unable to predict the future impact on depletion rates. The following is a
summary of capitalized costs (in thousands) excluded from depletion at December 31, 2010 by year
incurred.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
Prior |
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
Years |
|
|
Total |
|
Property acquisition |
|
$ |
79,308 |
|
|
$ |
5,680 |
|
|
$ |
11,851 |
|
|
$ |
2,775 |
|
|
$ |
99,614 |
|
Exploration
(including
geological and
geophysical costs) |
|
|
1,679 |
|
|
|
37 |
|
|
|
3,256 |
|
|
|
13,146 |
|
|
|
18,118 |
|
Drilling |
|
|
50,981 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,981 |
|
Capitalized interest |
|
|
7,876 |
|
|
|
3,902 |
|
|
|
1,902 |
|
|
|
540 |
|
|
|
14,220 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
139,844 |
|
|
$ |
9,619 |
|
|
$ |
17,009 |
|
|
$ |
16,461 |
|
|
$ |
182,933 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-29
BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued)
Oil and Natural Gas Reserves and Related Financial Data
Information with respect to Brighams oil and natural gas producing activities is presented in
the following tables. Reserve quantities, as well as certain information regarding future
production and discounted cash flows, were determined by Brighams registered independent petroleum
consultants, Cawley, Gillespie and Associates, Inc.
Oil and Natural Gas Reserve Data
The following tables present estimates of Brighams proved oil and natural gas reserves
prepared by independent petroleum consultants. Brigham emphasizes reserves are approximations and
are expected to change as additional information becomes available. Reservoir engineering is a
subjective process of estimating underground accumulations of oil and natural gas that cannot be
measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
|
Oil |
|
|
Gas |
|
|
|
(MBbls) |
|
|
(MMcf) |
|
Proved reserves at December 31, 2007 |
|
|
5,593 |
|
|
|
106,643 |
|
Revisions of previous estimates |
|
|
413 |
|
|
|
(7,834 |
) |
Extensions, discoveries and other additions |
|
|
1,637 |
|
|
|
3,866 |
|
Production |
|
|
(578 |
) |
|
|
(7,996 |
) |
|
|
|
|
|
|
|
Proved reserves at December 31, 2008 |
|
|
7,065 |
|
|
|
94,679 |
|
|
|
|
|
|
|
|
Revisions of previous estimates |
|
|
2,055 |
|
|
|
(28,742 |
) |
Extensions, discoveries and other additions |
|
|
8,354 |
|
|
|
6,367 |
|
Sales of mineral in place |
|
|
(37 |
) |
|
|
(13 |
) |
Production |
|
|
(814 |
) |
|
|
(5,892 |
) |
|
|
|
|
|
|
|
Proved reserves at December 31, 2009 |
|
|
16,623 |
|
|
|
66,399 |
|
|
|
|
|
|
|
|
Revisions of previous estimates (a) |
|
|
3,588 |
|
|
|
(856 |
) |
Extensions, discoveries and other additions (b) |
|
|
34,523 |
|
|
|
27,045 |
|
Purchase of mineral in place |
|
|
219 |
|
|
|
211 |
|
Sales of mineral in place |
|
|
(528 |
) |
|
|
(412 |
) |
Production |
|
|
(2,216 |
) |
|
|
(4,562 |
) |
|
|
|
|
|
|
|
Proved reserves at December 31, 2010 |
|
|
52,209 |
|
|
|
87,825 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at December 31: |
|
|
|
|
|
|
|
|
2007 |
|
|
3,321 |
|
|
|
49,367 |
|
2008 |
|
|
3,583 |
|
|
|
41,928 |
|
2009 |
|
|
5,342 |
|
|
|
29,178 |
|
2010 |
|
|
17,522 |
|
|
|
36,537 |
|
|
|
|
(a) |
|
Revisions of previous estimates include performance and technical revisions of 3,619 MBoe,
economic revisions of 895 MBoe, interest trades of (255) MBoe, and elimination of PUD reserves
that will not be developed within 5 years of (813) MBoe. |
|
(b) |
|
Extensions, discoveries and other additions include discoveries and associated PUDs of
39,030 MBoe, primarily in the Williston Basin. |
Proved reserves are estimated quantities of crude oil and natural gas, which geological and
engineering data indicate with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed reserves are proved
reserves that can be expected to be recovered through existing wells with existing equipment and
operating methods.
F-30
BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued)
Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein
The following table presents a standardized measure of discounted future net cash inflows (in
thousands) relating to proved oil and natural gas reserves. For 2008, future cash flows were
computed by applying year-end prices of crude oil and natural gas relating to Brighams proved
reserves to the estimated year-end quantities of those reserves. Under new rules issued by the
Securities and Exchange Commission, the estimated future net cash flows at December 31, 2010 and
2009 were determined using a 12-month average price. Future price changes were considered only to
the extent provided by contractual agreements in existence at year-end. Future production and
development costs were computed by estimating those expenditures expected to occur in developing
and producing the proved oil and natural gas reserves at the end of the year, based on year-end
costs. Actual future cash inflows may vary considerably, and the standardized measure does not
necessarily represent the fair value of Brighams oil and natural gas reserves.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Future cash inflows |
|
$ |
4,233,003 |
|
|
$ |
1,158,260 |
|
|
$ |
899,745 |
|
Future production costs |
|
|
(1,117,690 |
) |
|
|
(330,837 |
) |
|
|
(206,640 |
) |
Future development costs |
|
|
(770,356 |
) |
|
|
(266,733 |
) |
|
|
(160,304 |
) |
Future income tax expense |
|
|
(619,145 |
) |
|
|
(32,493 |
) |
|
|
(32,152 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash inflows |
|
|
1,725,812 |
|
|
|
528,197 |
|
|
|
500,649 |
|
10% annual discount for estimated timing of cash flows |
|
|
(859,699 |
) |
|
|
(281,721 |
) |
|
|
(221,353 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
866,113 |
|
|
$ |
246,476 |
|
|
$ |
279,296 |
|
|
|
|
|
|
|
|
|
|
|
Prices were adjusted to reflect applicable transportation and quality differentials on a
well-by-well basis to arrive at realized sales prices used to estimate Brighams reserves. The
prices used for Brighams reserve estimates were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
|
Oil |
|
|
Gas |
|
|
|
(Bbl) |
|
|
(MMbtu) |
|
December 31, 2010 |
|
$ |
79.43 |
|
|
$ |
4.38 |
|
December 31, 2009 |
|
|
61.18 |
|
|
$ |
3.87 |
|
December 31, 2008 |
|
|
44.60 |
|
|
$ |
5.71 |
|
Changes in the future net cash inflows discounted at 10% per annum follow (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Beginning of period |
|
$ |
246,476 |
|
|
$ |
279,296 |
|
|
$ |
394,514 |
|
Sales of oil and natural gas produced, net of production costs |
|
|
(143,169 |
) |
|
|
(48,439 |
) |
|
|
(107,144 |
) |
Previously estimated development costs incurred during the period |
|
|
69,829 |
|
|
|
16,574 |
|
|
|
51,494 |
|
Extensions and discoveries |
|
|
643,526 |
|
|
|
75,803 |
|
|
|
30,175 |
|
Net change of prices and production costs |
|
|
213,101 |
|
|
|
(41,750 |
) |
|
|
(184,497 |
) |
Change in future development costs |
|
|
(39,841 |
) |
|
|
6,874 |
|
|
|
(28,901 |
) |
Changes in production rates (timing) |
|
|
18,296 |
|
|
|
(17,557 |
) |
|
|
(2,201 |
) |
Revisions of previous quantity estimates |
|
|
84,417 |
|
|
|
(41,726 |
) |
|
|
(16,436 |
) |
Accretion of discount |
|
|
25,430 |
|
|
|
28,722 |
|
|
|
49,130 |
|
Change in income taxes |
|
|
(234,529 |
) |
|
|
99 |
|
|
|
88,868 |
|
Purchases of reserves in place |
|
|
6,688 |
|
|
|
|
|
|
|
|
|
Sales of reserves in place |
|
|
(9,877 |
) |
|
|
(591 |
) |
|
|
|
|
Other |
|
|
(14,234 |
) |
|
|
(10,829 |
) |
|
|
4,294 |
|
|
|
|
|
|
|
|
|
|
|
End of period |
|
$ |
866,113 |
|
|
$ |
246,476 |
|
|
$ |
279,296 |
|
|
|
|
|
|
|
|
|
|
|
F-31
BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION
Quarterly Financial Data (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2010 |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
1 |
|
|
2 |
|
|
3 |
|
|
4 |
|
Revenue |
|
$ |
32,573 |
|
|
$ |
44,930 |
|
|
$ |
36,610 |
|
|
$ |
55,609 |
|
Operating income (loss) |
|
|
13,081 |
|
|
|
19,336 |
|
|
|
9,364 |
|
|
|
18,663 |
|
Net income (loss)* |
|
|
11,315 |
|
|
|
18,473 |
|
|
|
(676 |
) |
|
|
13,784 |
|
Net income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.11 |
|
|
$ |
0.16 |
|
|
$ |
(0.01 |
) |
|
$ |
0.12 |
|
Diluted |
|
$ |
0.11 |
|
|
$ |
0.16 |
|
|
$ |
(0.01 |
) |
|
$ |
0.12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009 |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
1 |
|
|
2 |
|
|
3 |
|
|
4 |
|
Revenue |
|
$ |
18,486 |
|
|
$ |
10,514 |
|
|
$ |
19,867 |
|
|
$ |
21,477 |
|
Operating income (loss)* |
|
|
(115,152 |
) |
|
|
(2,787 |
) |
|
|
4,750 |
|
|
|
4,273 |
|
Net income (loss)* |
|
|
(119,071 |
) |
|
|
(6,960 |
) |
|
|
491 |
|
|
|
2,548 |
|
Net income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(2.60 |
) |
|
$ |
(0.12 |
) |
|
$ |
0.01 |
|
|
$ |
0.03 |
|
Diluted |
|
$ |
(2.60 |
) |
|
$ |
(0.12 |
) |
|
$ |
0.01 |
|
|
$ |
0.03 |
|
|
|
|
* |
|
Net income (loss) includes the impact from the loss on early redemption of Senior Notes in
the amount of $10.9 million for the third quarter of 2010. Operating income (loss) and Net
income (loss) include the impact from the writedown of the net capitalized costs of Brighams
oil and gas properties in the amounts of $114.8 million for the first quarter of 2009. |
F-32
INDEX TO EXHIBITS
|
|
|
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
|
|
3.1 |
|
|
|
|
Certificate of Incorporation (filed as Exhibit 3.1 to Brighams
Registration Statement on Form S-1 (Registration No. 333-22491) and
incorporated herein by reference) |
|
|
|
|
|
|
|
|
3.2 |
|
|
|
|
Certificates of Amendment of Certificate of Incorporation (filed as
Exhibit 3.1.1 to Brighams Registration Statement on Form S-3
(Registration No. 333-37558) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
3.3 |
|
|
|
|
Bylaws, as amended through May 28, 2009 (filed as Exhibit 3.5 to Brighams
Current Report on Form 8-K (filed May 28, 2009) and incorporated herein by
reference) |
|
|
|
|
|
|
|
|
3.4 |
|
|
|
|
Certificate of Amendment of Certificate of Incorporation of Brigham
Exploration Company dated June 14, 2006, (filed as Exhibit 3.4 to
Brighams Annual Report on Form 10-K for the year ended December 31, 2008
and incorporated herein by reference) |
|
|
|
|
|
|
|
|
3.5 |
|
|
|
|
Certificate of Amendment of Certificate of Incorporation of Brigham
Exploration Company dated October 7, 2009 (filed as Exhibit 3.5 to
Brighams Current Report on Form 8-K (filed October 13, 2009) and
incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.1 |
|
|
|
|
Form of Common Stock Certificate (filed as Exhibit 4.1 to Brighams
Registration Statement on Form S-1 (Registration No. 333-22491) and
incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.2 |
|
|
|
|
Certificate of Designations of Series A Preferred Stock (Par Value $.01
Per Share) of Brigham Exploration Company filed October 31, 2000 (filed as
Exhibit 4.1 to Brighams Current Report on Form 8-K, as amended (filed
November 8, 2000) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.3 |
|
|
|
|
Certificate of Amendment of Certificate of Designations of Series A
Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company,
filed March 2, 2001 (filed as Exhibit 4.2.1 to Brighams Annual Report on
Form 10-K for the year ended December 31, 2000 and incorporated herein by
reference) |
|
|
|
|
|
|
|
|
4.4 |
|
|
|
|
Certificate of Elimination of Certificate of Designations of Series A
Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company,
filed August 9, 2010 (filed as Exhibit 3.7 to Brighams Current Report on
Form 8-K (filed August 10, 2010) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.5 |
|
|
|
|
Certificate of Designations of Series B Preferred Stock (Par Value $.01
Per Share) of Brigham Exploration Company filed December 20, 2002 (filed
as Exhibit 4.4 to Brighams Annual Report on Form 10-K for the year ended
December 31, 2002 and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.6 |
|
|
|
|
Certificate of Elimination of Certificate of Designations of Series B
Preferred Stock of Brigham Exploration Company, dated June 4, 2004, (filed
as Exhibit 99.2 to Brighams Current Report on Form 8-K (filed July 20,
2004) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.7 |
|
|
|
|
Certificate of Designations of Series C Junior Participating Preferred
Stock of Brigham Exploration Company effective as of December 10, 2008
(filed as Exhibit 3.1 to Brighams Current Report on Form 8-K (filed
December 11, 2008) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.8 |
|
|
|
|
Certificate of Elimination of Certificate of Designations of Series C
Junior Participating Preferred Stock of Brigham Exploration Company
effective March 9, 2010 (filed as Exhibit 3.6 to Brighams Current Report
on Form 8-K (filed March 15, 2010) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.9 |
|
|
|
|
First Supplemental Indenture, dated September 27, 2010, among the Company,
the Guarantors and Wells Fargo Bank, National Association, as Trustee
(filed as Exhibit 4.16 to Brighams Current Report on Form 8-K (filed
October 1, 2010) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.10 |
|
|
|
|
Indenture, dated September 27, 2010, among the Company, the Guarantors and
Wells Fargo Bank, National Association, as Trustee (filed as Exhibit 4.17
to Brighams Current Report on Form 8-K (filed October 1, 2010) and
incorporated herein by reference) |
|
|
|
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
|
|
4.11 |
|
|
|
|
Rule 144A 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as
Exhibit 4.18 to Brighams Current Report on Form 8-K (filed October 1,
2010) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.12 |
|
|
|
|
Regulation S 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed
as Exhibit 4.19 to Brighams Current Report on Form 8-K (filed October 1,
2010) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.1 |
|
|
|
|
Amended and Restated Agreement of Limited Partnership of Brigham Oil &
Gas, L.P., dated December 30, 1997 by and among Brigham, Inc., Brigham
Holdings I, L.L.C. and Brigham Holdings II, L.L.C. (filed as Exhibit
10.1.4 to Brighams Annual Report on Form 10-K for the year ended December
31, 1998 and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.2 |
* |
|
|
|
Form Change of Control Agreement dated as of September 20, 1999 between
Brigham Exploration Company and certain Officers (filed as Exhibit 10.3 to
Brighams Quarterly Report on Form 10-Q for the fiscal quarter ended
September 30, 1999 and incorporated by reference herein) |
|
|
|
|
|
|
|
|
10.3 |
|
|
|
|
Fourth Amended and Restated Credit Agreement, dated June 29, 2005 between
Brigham Oil & Gas, L.P., Bank of America, N.A., The Royal Bank of Scotland
plc, BNP Paribas and Banc of America Securities LLC. (filed as Exhibit
10.1 to Brighams Quarterly Report on Form 10-Q for the fiscal quarter
ended June 30, 2005 and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.4 |
|
|
|
|
Resignation of Agent, Appointment of Successor Agent and Assignment of
Security Instruments dated June 29, 2005 by and among Brigham Oil & Gas,
L.P., Société Generale and Bank of America, N.A. (filed as Exhibit 10.2 to
Brighams Quarterly Report on Form 10-Q for the fiscal quarter ended June
30, 2005 and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.5 |
|
|
|
|
First Amendment to Fourth Amended and Restated Credit Agreement, between
Brigham Exploration Company and the banks named therein, dated April 10,
2006 (filed as Exhibit 10.3 to Brighams Current Report on Form 8-K, as
amended (filed April 24, 2006) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.6 |
|
|
|
|
Second Amendment to Fourth Amended and Restated Credit Agreement, between
Brigham Exploration Company and the banks named therein, dated March 27,
2007 (filed as Exhibit 10.3 to Brighams Current Report on Form 8-K (filed
on April 13, 2007) and incorporated in by reference) |
|
|
|
|
|
|
|
|
10.7 |
* |
|
|
|
Form of the Amended and Restated Indemnity Agreement (filed as Exhibit
99.1 to Brighams Current Report on Form 8-K, as amended (filed December
5, 2006), and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.8 |
|
|
|
|
Agreement Relating to Voting of Shares dated July 31, 2008, between
Brigham Exploration Company and DLJ Merchant Banking Partners III, L.P.,
DLJ Offshore Partners III, C.V., DLJ Offshore Partners III-1, C.V., DLJ
Offshore Partners III-2, C.V., DLJ MB Partners III GmbH & Co. KG,
Millennium Partners II, L.P., MBP III Plan Investors, L.P., DLJ ESC II,
L.P. and DLJMB Funding III, Inc. (filed as Exhibit 10.42 to Brighams
Current Report on Form 8-K (filed August 5, 2008) and incorporated herein
by reference) |
|
|
|
|
|
|
|
|
10.9 |
|
|
|
|
Third Amendment to the Fourth Amended and Restated Credit Agreement dated
as of November 7, 2008 (filed as Exhibit 10.43 to Brighams Current Report
on Form 8-K (filed November 12, 2008) and incorporated herein by
reference) |
|
|
|
|
|
|
|
|
10.10 |
* |
|
|
|
Amendment to the 1997 Incentive Plan, dated March 9, 2010 (filed as
Exhibit 10.46 to Brighams Current Report on Form 8-K (filed March 15,
2010) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.11 |
* |
|
|
|
Form of Restricted Stock Agreement under the 1997 Incentive Plan of
Brigham Exploration Company (filed as Exhibit 10.45 to Brighams Current
Report on Form 8-K (filed December 29, 2008) and incorporated herein by
reference) |
|
|
|
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
|
|
10.12 |
* |
|
|
|
Form of Option Agreement (Non-Qualified Stock Option) under the 1997
Incentive Plan of Brigham Exploration Company (filed as Exhibit 10.46 to
Brighams Current Report on Form 8-K (filed December 29, 2008) and
incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.13 |
* |
|
|
|
Form of Option Agreement (Incentive Option) under the 1997 Incentive Plan
of Brigham Exploration Company (filed as Exhibit 10.47 to Brighams
Current Report on Form 8-K (filed December 29, 2008) and incorporated
herein by reference) |
|
|
|
|
|
|
|
|
10.14 |
* |
|
|
|
Brigham Exploration Company 1997 Director Stock Option Plan (as amended
effective January 1, 2009) (filed as Exhibit 10.48 to Brighams Current
Report on Form 8-K (filed December 29, 2008) and incorporated herein by
reference) |
|
|
|
|
|
|
|
|
10.15 |
* |
|
|
|
Form of Non-Qualified Stock Option Agreement under the 1997 Director Stock
Option Plan (filed as Exhibit 10.49 to Brighams Current Report on Form
8-K (filed December 29, 2008) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.16 |
* |
|
|
|
Form of Amendment to the Change of Control Agreement (filed as Exhibit
10.50 to Brighams Current Report on Form 8-K (filed December 29, 2008)
and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.17 |
* |
|
|
|
Amendment to the Employment Agreement between the Company and Ben M.
Brigham dated as of December 23, 2008 (filed as Exhibit 10.51 to Brighams
Current Report on Form 8-K (filed December 29, 2008) and incorporated
herein by reference) |
|
|
|
|
|
|
|
|
10.18 |
|
|
|
|
Confirmation of Notice of Termination of Consulting Agreement with Harold
D. Carter, between Brigham Oil & Gas, L.P. and Harold D. Carter, effective
as of January 1, 2009 (filed as Exhibit 10.41 to Brighams Quarterly
Report on Form 10-Q for the fiscal quarter ended March 31, 2009 and
incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.19 |
* |
|
|
|
1997 Incentive Plan Amendment to Option Agreements, effective as of April
22, 2009 (filed as Exhibit 10.42 to Brighams Quarterly Report on Form
10-Q for the fiscal quarter ended March 31, 2009 and incorporated herein
by reference) |
|
|
|
|
|
|
|
|
10.20 |
|
|
|
|
Fourth Amendment to the Fourth Amended and Restated Credit Agreement dated
as of May 13, 2009 (filed as Exhibit 10.43 to Brighams Current Report on
Form 8-K (filed May 28, 2009) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.21 |
|
|
|
|
Fifth Amendment to the Fourth Amended and Restated Credit Agreement dated
as of July 24, 2009 (filed as Exhibit 10.45 to Brighams Current Report on
Form 8-K (filed July 28, 2009) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.22 |
* |
|
|
|
Form of Non-Qualified Stock Option Agreement (filed as Exhibit 10.49 to
Brighams Quarterly Report on Form 10-Q for the fiscal quarter ended June
30, 2009) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.23 |
* |
|
|
|
Form of Non-Qualified Stock Option Agreement under the 1997 Director Stock
Option Plan (filed as Exhibit 10.3 to Brighams Quarterly Report on Form
10-Q for the fiscal quarter ended September 30, 2009 and incorporated
herein by reference) |
|
|
|
|
|
|
|
|
10.24 |
* |
|
|
|
Form of Non-Qualified Stock Option Agreement (filed as Exhibit 10.4 to
Brighams Quarterly Report on Form 10-Q for the fiscal quarter ended
September 30, 2009 and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.25 |
* |
|
|
|
Form of Amendment to Non-Qualified Stock Option Agreements (filed as
Exhibit 10.5 to Brighams Quarterly Report on Form 10-Q for the fiscal
quarter ended September 30, 2009 and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.26 |
* |
|
|
|
Amendment to Brigham Exploration Company 1997 Director Stock Option Plan,
effective as of September 23, 2009 (filed as Exhibit 10.6 to Brighams
Quarterly Report on Form 10-Q for the fiscal quarter ended September 30,
2009 and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.27 |
* |
|
|
|
Amendment to Non-Qualified Stock Option Agreements under the 1997 Director
Stock Option Plan, effective as of September 23, 2009 (filed as Exhibit
10.7 to Brighams Quarterly Report on Form 10-Q for the fiscal quarter
ended September 30, 2009 and incorporated herein by reference) |
|
|
|
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
|
|
10.28 |
|
|
|
|
Sixth Amendment and Consent to the Fourth Amended and Restated Credit
Agreement dated as of May 28, 2010 between the Company and the banks named
therein (filed as Exhibit 10.47 to Brighams Current Report on Form 8-K
(filed June 3, 2010) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.29 |
|
|
|
|
Registration Rights Agreement, dated September 27, 2010, among the
Company, the Guarantors and the Initial Purchasers (filed as Exhibit 4.20
to Brighams Current Report on Form 8-K (filed October 1, 2010) and
incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.30 |
|
|
|
|
Seventh Amendment to the Fourth Amended and Restated Credit Agreement
dated as of September 10, 2010 between the Company and the banks named
therein (filed as Exhibit 10.48 to Brighams Current Report on Form 8-K
(filed September 13, 2010) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.31 |
|
|
|
|
Purchase Agreement dated September 16, 2010 among the Company, the
Guarantors and the Initial Purchasers. (filed as Exhibit 10.49 to
Brighams Current Report on Form 8-K (filed September 20, 2010) and
incorporated herein by reference) |
|
|
|
|
|
|
|
|
12.1 |
|
|
|
|
Statement Regarding Computation of Ratios |
|
|
|
|
|
|
|
|
21 |
|
|
|
|
Subsidiaries of the Registrant |
|
|
|
|
|
|
|
|
23.1 |
|
|
|
|
Consent of KPMG LLP, Independent Registered Public Accounting Firm |
|
|
|
|
|
|
|
|
23.2 |
|
|
|
|
Consent of Cawley, Gillespie & Associates, Inc. |
|
|
|
|
|
|
|
|
31.1 |
|
|
|
|
Certification of Chief Executive Officer pursuant to Sec. 302 of the
Sarbanes-Oxley Act of 2002 |
|
|
|
|
|
|
|
|
31.2 |
|
|
|
|
Certification of Chief Financial Officer pursuant to Sec. 302 of the
Sarbanes-Oxley Act of 2002 |
|
|
|
|
|
|
|
|
32.1 |
|
|
|
|
Certification of Chief Executive Officer pursuant to 18 U.S.C. SECTION 1350 |
|
|
|
|
|
|
|
|
32.2 |
|
|
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. SECTION 1350 |
|
|
|
|
|
|
|
|
99.1 |
|
|
|
|
Report of Cawley, Gillespie & Associates, Inc. |
|
|
|
* |
|
Management contract or compensatory plan. |
|
|
|
Filed herewith |