Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary note regarding forward-looking statements.”
Overview
We are an independent E&P company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the North Dakota and Montana regions of the Williston Basin. Since our inception, we have acquired properties that provide current production and significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken and Three Forks formations. OPNA conducts our domestic oil and natural gas E&P activities. We also operate a midstream services business through OMS and a well services business through OWS, both of which are separate reportable business segments that are complementary to our primary development and production activities. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation and, therefore, do not directly contribute to our consolidated results of operations.
Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. We built our Williston Basin assets through acquisitions and development activities, which were financed with a combination of capital from private investors, borrowings under our revolving credit facility, cash flows provided by operating activities, proceeds from our Notes, proceeds from our public equity offerings, the sale of certain non-core oil and gas properties and cash settlements of derivative contracts. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided an entry into a new area of interest or complemented our existing operations. In addition, the acquisition of non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.
Due to the geographic concentration of our oil and natural gas properties in the Williston Basin, we believe the primary sources of opportunities, challenges and risks related to our business for both the short and long-term are:
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|
•
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commodity prices for oil and natural gas;
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•
|
transportation capacity;
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•
|
availability and cost of services; and
|
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|
•
|
availability of qualified personnel.
|
Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations and may fluctuate widely in the future. As a result of current oil prices, we have increased our planned
2017
capital expenditures as compared to
2016
, excluding acquisitions, and we are continuing to concentrate our drilling activities in certain areas that are the most economic in the Williston Basin. Extended periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.
In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our oil and natural gas to a broader array of potential purchasers. We enter into crude oil sales contracts with purchasers who have access to crude oil transportation capacity, utilize derivative financial
instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows. Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead. Currently, we are flowing approximately
90%
of our gross operated oil production through these gathering systems. Please see “Item 1. Business—Marketing, transportation and major customers.”
Our quarterly average net realized oil prices and average price differentials are shown in the tables below.
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2016
|
|
Year ended
December 31, 2016
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Q1
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|
Q2
|
|
Q3
|
|
Q4
|
|
Average Realized Oil Prices ($/Bbl)(1)
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$
|
28.74
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|
|
$
|
40.81
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|
|
$
|
40.54
|
|
|
$
|
44.57
|
|
|
$
|
38.64
|
|
Average Price Differential
(2)
|
14
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%
|
|
11
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%
|
|
10
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%
|
|
10
|
%
|
|
11
|
%
|
|
|
|
|
|
|
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|
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2015
|
|
Year ended
December 31, 2015
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Q1
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|
Q2
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|
Q3
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|
Q4
|
|
Average Realized Oil Prices ($/Bbl)
(1)
|
$
|
40.73
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|
$
|
52.04
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|
$
|
41.61
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|
|
$
|
37.77
|
|
|
$
|
43.04
|
|
Average Price Differential
(2)
|
16
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%
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|
10
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%
|
|
10
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%
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|
10
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%
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|
12
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%
|
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2014
|
|
Year ended
December 31, 2014
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Q1
|
|
Q2
|
|
Q3
|
|
Q4
|
|
Average Realized Oil Prices ($/Bbl)
(1)
|
$
|
89.66
|
|
|
$
|
94.48
|
|
|
$
|
87.17
|
|
|
$
|
62.79
|
|
|
$
|
82.73
|
|
Average Price Differential
(2)
|
9
|
%
|
|
8
|
%
|
|
10
|
%
|
|
13
|
%
|
|
10
|
%
|
__________________
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(1)
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Realized oil prices do not include the effect of derivative contract settlements.
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(2)
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Price differential reflects the difference between realized oil prices and WTI crude oil index prices.
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Our market optionality on the crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations. Crude oil produced and sold in the Williston Basin has historically sold at a discount to WTI due to transportation costs and takeaway capacity. In the past, there have been periods when this discount has substantially increased due to oil production in the area increasing to a point that it temporarily surpassed the available pipeline transportation, rail transportation and refining capacity in the area. Expansions of both rail and pipeline facilities have reduced the prior constraint on oil transportation out of the Williston Basin and improved our price differentials received at the lease. In the first quarter of 2014, our average price differentials relative to WTI increased due to the pipeline market weakening as a result of refinery down time and increased U.S. and Canadian production. In the second and third quarters of 2014, stronger pipeline prices shifted more of our barrels towards the pipelines, but rail buyers had to compete with pipeline prices despite weaker Brent differentials, resulting in price differentials relative to WTI of approximately 9% to 11%. In the fourth quarter of 2014, as WTI crude oil prices declined, our price differentials increased as a percentage of WTI but remained relatively flat in terms of the dollar per barrel discount to WTI in the range of $9.00 to $10.50 per barrel of oil. In 2015, our price differentials relative to WTI strengthened as new pipelines opened to eastern Canada and U.S. markets and transportation on rail gradually declined. In the first quarter of 2015, as WTI further declined, our price differentials continued to increase as a percentage of WTI but decreased in terms of the dollar per barrel discount to WTI to an average of $7.85 per barrel of oil. In the second quarter of 2015, as WTI improved, our price differentials returned to approximately 10% as a percentage of WTI and continued to decrease in terms of the dollar per barrel discount to WTI to an average of $5.90 per barrel of oil. Since the third quarter of 2015, our price differentials have averaged less than $5.00 per barrel discount to WTI. We expect differentials to improve as takeaway capacity in the Williston Basin will increase by over 500,000 barrels of oil per day if the Dakota Access Pipeline is completed and put in service.
We believe our large concentrated acreage position provides us with a multi-year inventory of drilling projects and requires forward planning visibility for obtaining services and necessary permits to drill wells. As a result of current oil prices, we are planning to increase our well completions from
57
gross (
37.6
net) operated wells in
2016
to
76
gross (
51.7
net) operated wells in
2017
. Additionally, we have the ability to control the pace of completions to allow for additional financial flexibility. In
2016
, we wrote off
$0.9 million
of leases that we do not expect to develop before their
2017
contract expirations, as we continue to focus our
2017
drilling activities in the deepest part of our acreage in the Williston Basin.
Our
2016
,
2015
and
2014
activities included development and exploration drilling in the Williston Basin. Our current activities are focused on evaluating and developing our asset base and optimizing our operations. Based on the reserve reports prepared by our independent reserve engineers, we had
305.1
MMBoe of estimated net proved reserves with a PV-10 of
$2,627.8
million and a Standardized Measure of
$2,483.1 million
at December 31,
2016
, 218.2 MMBoe of estimated net proved reserves with a PV-10 of $2,022.7 million and a Standardized Measure of $1,914.3 million at December 31, 2015 and 272.1 MMBoe of estimated net proved reserves with a PV-10 of $5,481.4 million and a Standardized Measure of $3,981.7 million at December 31, 2014. Our
estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months for the years ended December 31,
2016
,
2015
and
2014
were
$42.60
per Bbl for oil and
$2.47
per MMBtu for natural gas,
$50.16
per Bbl for oil and
$2.63
per MMBtu for natural gas and
$95.28
per Bbl for oil and
$4.35
per MMBtu for natural gas, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Future operating costs, production taxes and capital costs were based on current costs as of each year-end. Changes in commodity prices and future operating costs may significantly affect the economic viability of drilling projects as well as the economic valuation and economic recovery of oil and gas reserves. An extended period of low oil prices could result in a significant decrease in our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure in the future.
Forward commodity prices and estimates of future production also play a significant role in determining impairment. As a result of lower commodity prices and their impact on our estimated future cash flows, we have continued to review our proved oil and natural gas properties for impairment. In 2014, we recorded a proved impairment loss of $40.0 million due to lower oil prices. In 2015 and 2016, we recorded an impairment charge of $9.4 million and
$1.1 million
to write down our proved properties held for sale to their estimated fair value, less costs to sell. No other proved impairment charges were recorded during the year ended December 31, 2016. In addition, the excess of our expected undiscounted future cash flows over the carrying value of our proved oil and natural gas properties in the Bakken and Three Forks formations has increased to $4,111.9 million as of December 31, 2016, an increase of approximately 225% as compared to an excess of $1,264.8 million at December 31, 2015. The underlying commodity prices embedded in our expected undiscounted cash flows were determined using NYMEX forward strip prices for five years, escalating 3% per year thereafter. Our expected undiscounted estimated cash flows also included a 3% inflation factor applied to the future operating and development costs after five years. If expected future commodity prices decline by approximately 30% as compared to December 31, 2016, holding all other factors constant, the expected undiscounted cash flows may not exceed the carrying value of our proved oil and natural gas properties in the Bakken and Three Forks formations, and as a result, we may recognize additional proved impairment charges in the future, and such impairment charges could exceed $2.5 billion assuming a discount rate of 10%.
2016
Highlights
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•
|
Average daily production was
50,372
Boe per day in 2016.
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•
|
We completed and placed on production
57
gross (
37.6
net) operated wells during
2016
. As of December 31,
2016
, the Company had
83
gross operated wells awaiting completion.
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•
|
We closed on an accretive acquisition of approximately 55,000 net acres on December 1, 2016 in the Williston Basin (the “Williston Basin Acquisition”) for a purchase price of
$765.8 million
, subject to further customary post-close purchase price adjustments.
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•
|
We completed and brought online our natural gas processing plant and other midstream infrastructure in Wild Basin.
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•
|
Excluding acquisitions, capital expenditures were $400.0 million for the year ended December 31,
2016
, a
31%
decrease as compared to
2015
.
|
|
|
•
|
We increased total net proved oil and natural gas reserves at December 31,
2016
by
40%
to
305.1
MMBoe, which included an increase of almost 30% in net proved developed reserves and more than 60% in net proved undeveloped reserves year over year.
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•
|
We ended the year with a leasehold position of
517,801
total net acres in the Williston Basin, primarily targeting the Bakken and Three Forks formations. In addition, we
increase
d our acreage that is held by production to
484,321
net acres as of December 31,
2016
.
|
|
|
•
|
We decreased lease operating expenses per Boe to
$7.35
per Boe for the year ended
December 31, 2016
.
|
|
|
•
|
We completed a $300.0 million public offering of senior unsecured convertible notes due 2023 and repurchased an aggregate principal amount of $447.0 million of our outstanding Senior Notes.
|
|
|
•
|
At December 31,
2016
, we had
$11.2 million
of cash and cash equivalents and had total liquidity of
$785.9
, including the availability under our revolving credit facility.
|
|
|
•
|
Net cash provided by operating activities was
$228.0 million
for the year ended December 31,
2016
. Adjusted EBITDA, a non-GAAP financial measure, was
$500.3 million
for the year ended December 31,
2016
. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net loss and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.
|
Results of Operations
Revenues
Our oil and gas revenues are derived from the sale of oil and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Our midstream revenues are primarily derived from salt water pipeline transport, salt water disposal, natural gas gathering and processing, fresh water sales and crude oil gathering and transportation. Our well services revenues are derived from well services, product sales and equipment rentals. A substantial majority of our midstream revenues and well services revenues are from services for third-party working interest owners in OPNA’s operated wells. Intercompany revenues for work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation and are therefore not included in midstream and well services revenue.
The following table summarizes our revenues and production data for the periods presented:
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|
|
Year ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
Operating results (in thousands):
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
Oil
|
$
|
596,580
|
|
|
$
|
692,497
|
|
|
$
|
1,231,251
|
|
Natural gas
|
38,925
|
|
|
29,175
|
|
|
72,753
|
|
Midstream
|
35,406
|
|
|
23,769
|
|
|
11,614
|
|
Well services
|
33,754
|
|
|
44,294
|
|
|
74,610
|
|
Total revenues
|
$
|
704,665
|
|
|
$
|
789,735
|
|
|
$
|
1,390,228
|
|
Production data:
|
|
|
|
|
|
Oil (MBbls)
|
15,174
|
|
|
16,091
|
|
|
14,883
|
|
Natural gas (MMcf)
|
19,573
|
|
|
14,002
|
|
|
10,691
|
|
Oil equivalents (MBoe)
|
18,436
|
|
|
18,424
|
|
|
16,664
|
|
Average daily production (Boe per day)
|
50,372
|
|
|
50,477
|
|
|
45,656
|
|
Average sales prices:
|
|
|
|
|
|
Oil, without derivative settlements (per Bbl)
(1)
|
$
|
38.64
|
|
|
$
|
43.04
|
|
|
$
|
82.73
|
|
Oil, with derivative settlements (per Bbl)
(1)(2)
|
46.68
|
|
|
66.06
|
|
|
83.19
|
|
Natural gas (per Mcf)
(3)
|
1.99
|
|
|
2.08
|
|
|
6.81
|
|
__________________
|
|
(1)
|
For the year ended December 31, 2016, average sales prices for oil are calculated using total oil revenues, excluding bulk oil sales of
$10.3 million
, divided by oil production.
|
|
|
(2)
|
Realized prices include gains or losses on cash settlements for our commodity derivatives, which do not qualify for and were not designated as hedging instruments for accounting purposes. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
|
|
|
(3)
|
Natural gas prices include the value for natural gas and natural gas liquids.
|
Year ended December 31,
2016
as compared to year ended December 31,
2015
Oil and gas revenues
. Our oil and gas revenues decreased
$86.2 million
, or
12%
, to
$635.5 million
during the year ended December 31,
2016
as compared to the year ended December 31,
2015
. The lower oil and natural gas sales prices decreased revenues by $72.1 million coupled with a $35.4 million decrease due to lower oil production amounts sold, partially offset by an $11.1 million increase due to higher natural gas production amounts sold during the year ended December 31,
2016
as compared to the year ended December 31,
2015
. In addition, oil and gas revenues included
$10.3 million
of bulk oil sales related to marketing activities during the year ended
December 31, 2016
. Average oil sales prices, without derivative settlements, decreased by $
4.40
per barrel to an average of
$38.64
per barrel, and average natural gas sales prices, which include the value for natural gas and natural gas liquids, decreased by
$0.09
per Mcf to an average of
$1.99
per Mcf for the year ended December 31,
2016
as compared to the year ended December 31,
2015
. Average daily production sold decreased by
105
Boe per day to
50,372
Boe per day during the year ended December 31,
2016
as compared to the year ended December 31,
2015
. The decrease in average daily production sold was primarily a result of the natural decline in production in wells that were producing as of December 31,
2015
, coupled with the divestiture completed on April 1, 2016, which resulted in a decrease in average daily production of approximately 411 Boe per day during the year ended December 31, 2016. This decrease was
offset by our
38.1
total net well completions in the core of the Williston Basin, which had higher gas to oil ratios that resulted in a 40% increase in natural gas production sold year over year, and the Williston Basin Acquisition completed on December 1, 2016. See Note 6 to our audited consolidated financial statements for a description of our acquisitions and divestitures.
Midstream revenues
. Midstream revenues were
$35.4 million
for the year ended December 31,
2016
, which was a
$11.6 million
increase year over year. This increase was driven by a $6.1 million increase related to higher natural gas volumes gathered and processed with the start up of our natural gas processing plant in the third quarter of 2016, coupled with a $6.0 million increase related to increased water volumes flowing through our salt water disposal systems as a result of new well connections and capacity additions.
Well services revenues.
In response to the low commodity price environment, we decreased the pace of our well completions and reduced OWS to one fracturing fleet during the first quarter of 2016. As a result, our well services revenues decreased by
$10.5 million
to
$33.8 million
for the year ended December 31,
2016
as compared to the year ended December 31,
2015
. Well completion revenue decreased $7.8 million year over year due to the decreased activity, partially offset by the impact of OWS completing OPNA wells with a higher average third-party working interest year over year. In addition, product sales to third parties decreased $1.7 million as a result of OWS completing all of OPNA’s operated wells and equipment rentals decreased $1.0 million in 2016 as compared to 2015.
Year ended December 31, 2015 as compared to year ended December 31, 2014
Oil and gas revenues
. Our oil and gas revenues decreased
$582.3 million
, or
45%
, to
$721.7 million
during the year ended December 31, 2015 compared to the year ended December 31, 2014, primarily due to lower realized oil and natural gas sales prices, partially offset by increased production volumes sold. Average daily production sold increased by 4,821 Boe per day, or 11%, to 50,477 Boe per day during the year ended December 31, 2015 as compared to the year ended December 31, 2014. The increase in average daily production sold was primarily a result of our 64.3 total net well completions in the Williston Basin during 2015, offset by the natural decline in production in wells that were producing as of December 31, 2014. Production from wells completed contributed to average daily production during 2015 by approximately 11,366 Boe per day. Average oil sales prices, without derivative settlements, decreased by $39.69 per barrel, or 48%, to an average of $43.04 per barrel, and average natural gas sales prices, which include the value for natural gas and natural gas liquids, decreased by $4.73 per Mcf, or 69%, to an average of $2.08 per Mcf for the year ended December 31, 2015 as compared to the year ended December 31, 2014. The lower oil and natural gas sales prices decreased revenues by $641.2 million, partially offset by higher production amounts sold, which increased revenues by $58.9 million during the year ended December 31, 2015.
Midstream revenues
. Midstream revenues totaled $23.8 million for the year ended December 31, 2015, a $12.2 million increase year over year, primarily due to a $9.1 million increase in salt water disposal revenue due to increased water volumes flowing through our salt water disposal systems as a result of increased well connections and capacity additions coupled with a $1.9 million increase in fresh water sales revenue.
Well services revenues.
Well services revenues decreased $30.3 million for the year ended December 31, 2015 as compared to the year ended December 31, 2014 primarily due to a $26.8 million decrease in product sales to third parties as a result of OWS completing substantially all of OPNA’s operated wells in 2015, coupled with a decrease of $3.1 million in equipment rentals as a result of running fewer rigs in 2015 as compared to 2014. Well completion activity increased year over year, but OWS completed OPNA wells with a lower average third-party working interest in 2015 as compared to 2014, resulting in a net decrease of $0.3 million in well completion revenue. While a lower average third-party working interest decreases the well completion revenue recognized in our consolidated results of operations, it improves our capital expenditures by reducing OPNA well costs.
Expenses and other income
The following table summarizes our operating expenses, gain on sale of properties and other income and expenses for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands, except per Boe of production)
|
Expenses:
|
|
|
|
|
|
Lease operating expenses
|
$
|
135,444
|
|
|
$
|
144,481
|
|
|
$
|
169,600
|
|
Midstream operating expenses
|
9,003
|
|
|
6,198
|
|
|
4,647
|
|
Well services operating expenses
|
17,009
|
|
|
21,833
|
|
|
45,605
|
|
Marketing, transportation and gathering expenses
|
40,366
|
|
|
31,610
|
|
|
29,133
|
|
Production taxes
|
56,565
|
|
|
69,584
|
|
|
127,648
|
|
Depreciation, depletion and amortization
|
476,331
|
|
|
485,322
|
|
|
412,334
|
|
Exploration expenses
|
1,785
|
|
|
2,369
|
|
|
3,064
|
|
Rig termination
|
—
|
|
|
3,895
|
|
|
—
|
|
Impairment
|
4,684
|
|
|
46,109
|
|
|
47,238
|
|
General and administrative expenses
|
93,008
|
|
|
92,498
|
|
|
92,306
|
|
Total expenses
|
834,195
|
|
|
903,899
|
|
|
931,575
|
|
Gain (loss) on sale of properties
|
(1,303
|
)
|
|
—
|
|
|
186,999
|
|
Operating income (loss)
|
(130,833
|
)
|
|
(114,164
|
)
|
|
645,652
|
|
Other income (expense):
|
|
|
|
|
|
Net gain (loss) on derivative instruments
|
(105,317
|
)
|
|
210,376
|
|
|
327,011
|
|
Interest expense, net of capitalized interest
|
(140,305
|
)
|
|
(149,648
|
)
|
|
(158,390
|
)
|
Gain on extinguishment of debt
|
4,741
|
|
|
—
|
|
|
—
|
|
Other income (expense)
|
160
|
|
|
(2,935
|
)
|
|
195
|
|
Total other income (expense)
|
(240,721
|
)
|
|
57,793
|
|
|
168,816
|
|
Income (loss) before income taxes
|
(371,554
|
)
|
|
(56,371
|
)
|
|
814,468
|
|
Income tax benefit (expense)
|
128,538
|
|
|
16,123
|
|
|
(307,591
|
)
|
Net income (loss)
|
$
|
(243,016
|
)
|
|
$
|
(40,248
|
)
|
|
$
|
506,877
|
|
Costs and expenses (per Boe of production):
|
|
|
|
|
|
Lease operating expenses
|
$
|
7.35
|
|
|
$
|
7.84
|
|
|
$
|
10.18
|
|
Marketing, transportation and gathering expenses
|
2.19
|
|
|
1.72
|
|
|
1.75
|
|
Production taxes
|
3.07
|
|
|
3.78
|
|
|
7.66
|
|
Depreciation, depletion and amortization
|
25.84
|
|
|
26.34
|
|
|
24.74
|
|
General and administrative expenses
|
5.04
|
|
|
5.02
|
|
|
5.54
|
|
Year ended December 31,
2016
as compared to year ended December 31,
2015
Lease operating expenses
. Lease operating expenses decreased
$9.0 million
to
$135.4 million
for the year ended December 31,
2016
as compared to the year ended December 31,
2015
. The decrease was primarily due to an increase in salt water disposal volumes being transported on OMS pipelines and injected in OMS salt water disposal wells coupled with the completion of wells in the core that had lower water to oil ratios, partially offset by higher costs associated with operating an increased number of producing wells. Utilizing our own infrastructure for salt water disposal enables us to lower operating costs through increased operational efficiency. We completed and placed on production
38.1
total net wells in the Williston Basin during the year ended December 31,
2016
as compared to 64.3 total net wells completed and placed on production during the year ended December 31,
2015
. Lease operating expenses decreased from
$7.84
per Boe for the year ended December 31,
2015
to
$7.35
per Boe for the year ended December 31,
2016
due to the lower costs.
Midstream operating expenses
. Midstream operating expenses represent third-party working interest owners’ share of operating expenses incurred by OMS. The $2.9 million increase for the year ended December 31,
2016
as compared to the year ended December 31,
2015
was primarily related to the start up of our natural gas processing plant in the third quarter of 2016 coupled
with an increase in water trucking expenses due to produced water from OPNA exceeding OMS salt water disposal capacity in certain areas and at certain times.
Well services operating expenses.
Well services operating expenses represent third-party working interest owners’ share of completion service costs, cost of goods sold and operating expenses incurred by OWS. The
$4.8 million
decrease for the year ended December 31,
2016
as compared to the year ended December 31,
2015
was primarily attributable to the lower well completion activity, partially offset by OWS completing OPNA wells with a higher average third-party working interest in the year ended December 31,
2016
as compared to December 31,
2015
.
Marketing, transportation and gathering expenses
. Marketing, transportation and gathering expenses increased
$8.8 million
year over year, or a
$0.47
increase per Boe, which was primarily attributable to a
$10.3 million
increase in costs related to bulk purchases coupled with a $0.4 million increase in natural gas gathering and processing expenses related to additional well connections on OMS infrastructure and the start up of our natural gas processing plant in the third quarter of 2016, offset by a decrease year over year of $1.2 million in the write down of our crude oil inventory to the lower of cost or market value at year-end and a $0.8 million decrease in oil transportation costs, primarily driven by lower trucking costs. Excluding non-cash valuation adjustments and bulk purchases, our marketing, transportation and gathering expenses on a per Boe basis remained relatively consistent at
$1.60
and
$1.62
for the years ended December 31,
2016
and
2015
, respectively.
Production taxes
. Our production taxes for the years ended December 31,
2016
and
2015
were
9.0%
and 9.6%, respectively, as a percentage of oil and natural gas sales. The production tax rate decreased year over year primarily due to reduced extraction tax rates in North Dakota beginning in January 2016. For the years ended December 31,
2016
and
2015
, the percentage of our total production located in North Dakota was approximately 92% and 88%, respectively. In 2015, North Dakota had a crude oil tax structure based on a 5% production tax and a 6.5% oil extraction tax, resulting in a combined tax rate of 11.5% of crude oil revenues. In 2016, the North Dakota oil extraction tax was reduced to 5%, resulting in a combined tax rate of 10% of crude oil revenues.
Depreciation, depletion and amortization (“DD&A”)
. DD&A expense decreased
$9.0 million
to
$476.3 million
for the year ended December 31,
2016
as compared to the year ended December 31,
2015
. The decrease in DD&A expense for the year ended December 31,
2016
was primarily due to a decrease in the average DD&A rate to
$25.84
per Boe for the year ended December 31,
2016
as compared to
$26.34
per Boe for the year ended December 31,
2015
. The decrease in the DD&A rate was primarily due to lower well costs and higher recoverable reserves.
Rig termination
. We did not early terminate any drilling rig contracts during the year ended December 31, 2016. As a result of our lowered 2015 capital expenditure program, we elected to early terminate certain drilling rig contracts and recorded a rig termination expense of $3.9 million for the year ended
December 31, 2015
.
Impairment
. During the years ended December 31, 2016 and 2015, we recorded total impairment charges of
$4.7 million
and
$46.1 million
, respectively. To adjust the carrying value of our properties held for sale to their estimated fair value, determined based on the expected sales price less costs to sell, we recorded impairment charges of
$3.6 million
and
$9.4 million
for the years ended December 31, 2016 and 2015, respectively. No other impairment charges of proved oil and gas or other properties were recorded in
2016
or
2015
. We also recorded non-cash impairment charges of
$0.2 million
and
$14.4 million
during the years ended December 31,
2016
and
2015
, respectively, for unproved properties due to leases that expired during the period. As a result of periodic assessments of unproved properties not held-by-production, we recorded additional impairment charges of
$0.9 million
and
$22.2 million
related to acreage expiring in future periods because there were no plans to drill or extend the leases prior to their expiration. During the year ended December 31, 2015, these impairment charges included $15.2 million related to leases that expired during the year ended December 31,
2016
. Consequently, lower impairment charges for unproved properties were recorded during the year ended December 31,
2016
as most leases that expired during the period had been previously impaired. In determining the amount of non-cash impairment charges for such periods, we considered the application of the factors described under “Critical accounting policies and estimates—Impairment of proved properties” and “Critical accounting policies and estimates—Impairment of unproved properties.”
General and administrative (“G&A”) expenses
. Our G&A expenses increased
$0.5 million
for the year ended December 31,
2016
from
$92.5 million
for the year ended December 31,
2015
. OWS G&A increased by $3.6 million primarily due to OWS completing OPNA wells with a higher average third-party working interest during the year ended December 31,
2016
as compared to the year ended December 31,
2015
. Excluding our intercompany elimination, gross OWS G&A decreased $11.9 million. E&P G&A was $79.0 million and $83.0 million for the years ended December 31,
2016
and
2015
, respectively. The decreases in gross OWS G&A and E&P G&A were primarily due to lower compensation expenses due to a decrease in employee headcount. OMS G&A increased $0.9 million for the year ended December 31,
2016
as compared to December 31,
2015
primarily due to increased employee compensation due to organizational growth within this segment due to the start up of our natural gas processing plant in the third quarter of 2016. Consolidated G&A expenses included non-cash amortization
for stock-based compensation of
$24.1 million
and $25.3 million in
2016
and
2015
, respectively. Our full-time employee headcount decreased to
477
as of December 31,
2016
from 535 as of December 31,
2015
.
Loss on sale of properties.
For the year ended December 31,
2016
, we recognized a
$1.3 million
loss related to the sale of certain legacy wells that have been producing from conventional reservoirs such as the Madison, Red River and other formations in the Williston Basin other than the Bakken or Three Forks formations. No gain or loss on sale of properties was recorded in the year ended December 31,
2015
.
Derivatives
. As a result of entering into derivative contracts and the effect of the forward strip oil price changes, we incurred a $105.3 million net loss on derivative instruments, including net cash settlement receipts of
$122.0 million
, for the year ended December 31,
2016
, and a $210.4 million net gain on derivative instruments, including net cash settlement receipts of $370.4 million, for the year ended December 31, 2015. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
Interest expense
. Interest expense decreased
$9.3 million
to
$140.3 million
for the year ended December 31,
2016
as compared to the year ended December 31,
2015
. The decrease was primarily due to the repurchase of Senior Notes, which decreased interest costs, and a decrease in interest expense incurred on borrowings under our revolving credit facility. These decreases were partially offset by interest expense related to our senior unsecured convertible notes issued in September 2016, which includes debt discount amortization, and a decrease in capitalized interest due to lower work in progress as a result of the completion of our natural gas processing plant in the third quarter of 2016. Interest expense incurred on borrowings under our revolving credit facility decreased by $2.9 million during
2016
as compared to
2015
due to a lower average borrowings year over year. For the year ended December 31,
2016
, the weighted average debt outstanding under our revolving credit facility was
$258.3 million
, and the weighted average interest rate incurred on the outstanding borrowings was
2.3%
. For the year ended December 31, 2015, the weighted average debt outstanding under our revolving credit facility was
$261.2 million
, and the weighted average interest rate incurred on the outstanding borrowings was
1.8%
. We capitalized
$16.8 million
and $18.6 million of interest costs for the years ended December 31,
2016
and
2015
, respectively, which will be amortized over the life of the related assets.
Gain on extinguishment of debt.
During the year ended December 31,
2016
, we repurchased an aggregate principal amount of $447.0 million of our outstanding senior unsecured notes for an aggregate cost of $435.9 million, including accrued interest and fees. For the year ended December 31,
2016
, we recognized a pre-tax gain related to the repurchase of $4.7 million, which included unamortized deferred financing costs write-offs of $6.4 million. During the year ended December 31,
2015
, we did not repurchase any portion of our outstanding senior unsecured notes.
Income tax benefit.
Our income tax benefit for the years ended December 31,
2016
and
2015
was recorded at
34.6%
and
28.6%
, respectively, of pre-tax loss. The effective tax rates for both years were lower than the combined federal statutory rate and the statutory rates for the states in which we conduct business due to the impact of permanent differences on our pre-tax loss. The permanent differences were primarily for compensation amounts expensed for book purposes versus the amounts deductible for income tax purposes related to stock-based compensation vesting during years ended December 31,
2016
and
2015
at stock prices lower than the grant date values. During the year ended December 31,
2016
, we recorded a valuation allowance of $0.8 million and $0.6 million for Montana net operating losses and federal charitable contribution carryovers, respectively, based on management’s assessment that it is more likely than not that these net deferred tax assets will not be realized prior to their expiration due to their short carryover periods, current economic conditions and expectations for the future.
Year ended December 31, 2015 as compared to year ended December 31, 2014
Lease operating expenses
. Lease operating expenses decreased
$25.1 million
to
$144.5 million
for the year ended December 31,
2015
as compared to the year ended December 31,
2014
. This decrease was primarily due to lower workover costs and an increase in salt water disposal volumes being transported on OMS pipelines and injected in OMS salt water disposal wells, partially offset by higher costs associated with operating an increased number of producing wells. We completed and placed on production
64.3
total net wells in the Williston Basin during the year ended December 31,
2015
as compared to 151.1 total net wells completed and placed on production during the year ended December 31,
2014
. Lease operating expenses decreased from
$10.18
per Boe for the year ended December 31,
2014
to
$7.84
per Boe for the year ended December 31,
2015
due to the lower costs and increase in oil and natural gas production.
Midstream operating expenses
. The
$1.6 million
increase in midstream operating expenses for the year ended December 31,
2015
as compared to the year ended December 31,
2014
was primarily related to salt water pipeline and disposal operating expenses and fresh water purchases.
Well services operating expenses.
The
$23.8 million
decrease in well services operating expenses for the year ended December 31,
2015
as compared to the year ended December 31,
2014
was attributable to a decrease in well completion costs as a result of lower well completion product sales to third parties due to OWS completing substantially all of OPNA’s operated wells, coupled with OWS completing OPNA wells with a lower average third-party working interest in the year ended December 31,
2015
as compared to December 31,
2014
.
Marketing, transportation and gathering expenses
. Marketing, transportation and gathering expenses increased
$2.5 million
year over year, or a
$0.03
decrease per Boe, which was primarily attributable to a $1.4 million increase in natural gas gathering charges related to additional well connections on OMS infrastructure, a $1.4 million increase in oil transportation costs associated with having additional wells connected to third-party infrastructure and a $0.3 million increase in our pipeline imbalance. These increases were partially offset by a decrease year over year of $0.9 million in the write down of our crude oil inventory to the lower of cost or market value at year-end. Excluding non-cash valuation adjustments, our marketing, transportation and gathering expenses on a per Boe basis would have remained constant at
$1.62
and
$1.61
for the years ended December 31,
2015
and
2014
, respectively. The transporting of volumes through third-party oil gathering pipelines increases marketing, transportation and gathering expenses but improves oil price realizations by reducing transportation costs included in our oil price differential for sales at the wellhead.
Production taxes
. Our production taxes for the years ended December 31,
2015
and
2014
were
9.6%
and 9.8%, respectively, as a percentage of oil and natural gas sales. The production tax rate decreased slightly year over year primarily due to reduced extraction tax rates triggered by lower oil prices on certain North Dakota wells, partially offset by an increased weighting of wells in North Dakota, which has a higher average production tax rate as compared to Montana. For the years ended December 31,
2015
and
2014
, the percentage of our total production located in North Dakota was approximately 88% and 86%, respectively. In 2015 and 2014, North Dakota had a crude oil tax structure based on a 5% production tax and a 6.5% oil extraction tax, resulting in a combined tax rate of 11.5% of crude oil revenues.
Depreciation, depletion and amortization
. DD&A expense increased
$73.0 million
to
$485.3 million
for the year ended December 31,
2015
as compared to the year ended December 31,
2014
. The increase in DD&A expense for the year ended December 31,
2015
was primarily due to an increase in the average DD&A rate per Boe year over year coupled with production increases from our wells completed during
2015
. The DD&A rate for the year ended December 31,
2015
was
$26.34
per Boe as compared to
$24.74
per Boe for the year ended December 31,
2014
. The increase in the DD&A rate was primarily due to lower recoverable reserves related to lower oil and natural gas prices and increased exploratory and delineation drilling in the Three Forks formation.
Rig termination
. As a result of our lowered 2015 capital expenditure program, we elected to early terminate certain drilling rig contracts and recorded a rig termination expense of
$3.9 million
for the year ended
December 31, 2015
. We did not early terminate any drilling rig contracts during the year ended
December 31, 2014
or
2013
.
Impairment
. Due to lower expected future oil prices, we reviewed our proved oil and natural gas properties for impairment as of December 31,
2015
and
2014
. For the year ended December 31, 2015, we recorded an impairment loss of
$9.4 million
to adjust the carrying value of our proved oil and natural gas properties held for sale to their estimated fair value. For the year ended December 31, 2014, we determined that the carrying value exceeded expected undiscounted cash flows for certain legacy wells that have been producing from conventional reservoirs such as the Madison, Red River and other formations in the Williston Basin other than the Bakken or Three Forks formations. As a result, we recorded an impairment loss of $40.0 million to adjust the carrying amount of these assets to fair value. During the years ended December 31,
2015
and
2014
, we also recorded non-cash impairment charges of
$36.6 million
and
$7.3 million
, respectively, for unproved properties due to leases that expired during the period and periodic assessments of unproved properties. The
2015
and
2014
impairment charges included
$22.2 million
related to acreage expiring in 2016 and 2017 and
$2.9 million
related to acreage expiring in 2015 and 2016, respectively, as a result of periodic assessments because there were no plans to drill or extend the leases prior to their expiration. In determining the amount of non-cash impairment charges for such periods, we considered the application of the factors described under “Critical accounting policies and estimates—Impairment of proved properties” and “Critical accounting policies and estimates—Impairment of unproved properties.”
General and administrative expenses
. Our G&A expenses increased
$0.2 million
to
$92.5 million
for the year ended December 31,
2015
as compared to the year ended December 31,
2014
. E&P G&A was $83.0 million and $80.4 million for the years ended December 31,
2015
and
2014
, respectively. The $2.6 million increase in E&P G&A was primarily due to increased employee compensation expenses, partially offset by increased shared services allocations to our OWS and OMS segments. OMS G&A increased $1.3 million for the year ended December 31,
2015
as compared to December 31,
2014
primarily due to increased employee compensation due to organizational growth within this segment. OWS G&A decreased by $3.6 million primarily due to OWS completing OPNA wells with a lower average third-party working interest in the year ended December 31,
2015
as compared to
2014
. Consolidated G&A expenses included non-cash amortization for stock-based compensation of
$25.3 million
and
$21.3 million
in
2015
and
2014
, respectively. While our full-time employee headcount decreased to 535 as of December 31,
2015
from 558 as of December 31,
2014
, our average employee headcount was higher during 2015 as compared to 2014.
Gain on sale of properties.
No gain or loss on sale of properties was recorded in the year ended December 31,
2015
. In the year ended December 31, 2014, we recognized a
$187.0 million
gain related to the divestiture of certain non-operated properties in and around our Sanish position.
Derivatives
. As a result of entering into derivative contracts and the effect of the forward strip oil price changes, we incurred a
$210.4 million
net gain on derivative instruments, including net cash settlement receipts of
$370.4 million
, for the year ended December 31,
2015
, and a $327.0 million net gain on derivative instruments, including net cash settlement receipts of $6.8 million, for the year ended December 31, 2014.
Interest expense
. Interest expense decreased
$8.7 million
to
$149.6 million
for the year ended December 31,
2015
as compared to the year ended December 31,
2014
. The decrease was primarily due to increased interest costs capitalized due to increased work in progress, including the natural gas processing plant we were constructing in Wild Basin and
85
wells waiting on completion as of December 31,
2015
. Interest expense incurred on borrowings under our revolving credit facility remained relatively constant during
2015
as compared to
2014
. For the year ended December 31,
2015
, the weighted average debt outstanding under our revolving credit facility was
$261.2 million
and the weighted average interest rate incurred on the outstanding borrowings was
1.8%
. For the year ended December 31, 2014, the weighted average debt outstanding under our revolving credit facility was
$272.3 million
and the weighted average interest rate incurred on the outstanding borrowings was
1.8%
. We capitalized
$18.6 million
and $8.8 million of interest costs for the years ended December 31,
2015
and
2014
, respectively, which will be amortized over the life of the related assets.
Income tax benefit (expense).
Income tax benefit for the year ended December 31,
2015
was recorded at
28.6%
of pre-tax loss, and income tax expense for the year ended December 31,
2014
was recorded at
37.8%
of pre-tax net income. While our 2014 effective tax rate was consistent with the statutory tax rate applicable to the U.S. and the blended state rate for the states in which we conduct business, our effective tax rate for the year ended December 31, 2015 was lower due to permanent differences between the amounts expensed for book purposes versus the amounts deductible for income tax purposes related to stock-based compensation vesting during the year ended December 31, 2015 at stock prices lower than the grant date values, partially offset by a reduction in the North Dakota statutory tax rate in 2015.
Liquidity and capital resources
Our primary sources of liquidity as of the date of this report have been proceeds from our Notes, borrowings under our revolving credit facility, proceeds from public equity offerings, cash flows from operations, the sale of certain non-core oil and gas properties and cash settlements of derivative contracts. Our primary uses of cash have been for the acquisition and development of oil and natural gas properties and midstream infrastructure, payment of operating and general and administrative costs, interest payments on outstanding debt and repurchases of Senior Notes. We continually monitor potential capital sources, including equity and debt financings and potential asset monetizations, in order to enhance liquidity and decrease leverage. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.
Our cash flows for the years ended December 31,
2016
,
2015
and
2014
are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Net cash provided by operating activities
|
$
|
228,018
|
|
|
$
|
359,815
|
|
|
$
|
872,516
|
|
Net cash used in investing activities
|
(1,070,828
|
)
|
|
(479,148
|
)
|
|
(1,077,452
|
)
|
Net cash provided by financing activities
|
844,306
|
|
|
83,252
|
|
|
158,846
|
|
Net change in cash and cash equivalents
|
$
|
1,496
|
|
|
$
|
(36,081
|
)
|
|
$
|
(46,090
|
)
|
Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. Prices for oil have declined significantly since mid-2014, which has substantially decreased our cash flows provided by operating activities. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the change in oil and natural gas prices on a portion of our production, thereby mitigating our exposure to oil and natural gas price declines, but these transactions may also limit our cash
flow in periods of rising oil and natural gas prices. As of December 31, 2016, our derivative contracts in place cover 12.0 MMBbls of crude oil and 5.5 MMBtus of natural gas in 2017.
On February 2, 2016, we completed a public equity offering resulting in net proceeds of $182.8 million, after deducting underwriting discounts and commissions and estimated offering expenses, which was used for general corporate purposes.
In September 2016, we issued $300.0 million of 2.625% senior unsecured convertible notes due September 15, 2023 (the “Senior Convertible Notes”), which resulted in aggregate net proceeds to us of
$291.9 million
, which we used to fund the tender offers to repurchase certain outstanding Senior Notes (as defined below) (the “Tender Offers”). As a result of the Tender Offers, we repurchased an aggregate principal amount of
$362.4 million
of our outstanding Senior Notes, for an aggregate cost of
$371.4 million
, including accrued interest and fees. In addition to the Tender Offers, we repurchased an aggregate principal amount of
$84.6 million
of the outstanding Senior Notes for an aggregate cost of
$64.5 million
, including accrued interest and fees, during the year ended
December 31, 2016
.
On October 21, 2016, we completed a public equity offering resulting in net proceeds of $584.0 million, after deducting underwriting discounts and commissions and estimated offering expenses, which was used to fund a portion of the Williston Basin Acquisition, which closed on December 1, 2016.
Our existing revolving credit facility provides additional liquidity, with a current borrowing base and elected commitment amount of
$1,150.0 million
. The next redetermination of the borrowing base is scheduled for April 1, 2017.
We believe we have adequate liquidity to fund planned 2017 capital expenditures and to meet our near-term future obligations. For additional information on the impact of changing prices on our financial position, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”
Cash flows provided by operating activities
Net cash provided by operating activities was
$228.0 million
,
$359.8 million
and
$872.5 million
for the years ended December 31,
2016
,
2015
and
2014
, respectively. The decrease in cash flows provided by operating activities for the year ended December 31,
2016
as compared to
2015
was primarily the result of the
10%
decrease in realized prices for oil and a
6%
decrease in oil production coupled with decreased well services activity, partially offset by a 40% increase in natural gas production and increases in natural gas gathering and processing, salt water pipeline transport and salt water disposal. The decrease in cash flows provided by operating activities for the year ended December 31,
2015
as compared to
2014
was primarily the result of the 48% decrease in realized prices for oil and the 69% decrease in realized prices for natural gas coupled with decreases in well completion product sales to third parties, offset by our 11% increase in oil and natural gas production and increases in salt water pipeline transport, salt water disposal and fresh water sales.
Working capital.
Our working capital fluctuates primarily as a result of changes in commodity pricing and production volumes, capital spending to fund our exploratory and development initiatives and acquisitions and the impact of our outstanding derivative instruments. We had a working capital deficit of
$142.6 million
at December 31,
2016
, however, we believe we have adequate liquidity to meet our working capital requirements. As of
December 31, 2016
, we had
$785.9 million
of liquidity available, including
$11.2 million
in cash and cash equivalents and
$774.7 million
of unused borrowing base committed capacity available under our revolving credit facility. As of December 31, 2015, we had a working capital deficit of $5.3 million. The year over year increase in our working capital deficit was primarily driven by a decrease in the fair value of our outstanding short-term derivative instruments at December 31, 2016 as compared to December 31, 2015 due to increases in forward strip oil prices.
Cash flows used in investing activities
We had net cash flows used in investing activities of
$1,070.8 million
, $
479.1 million
and $
1,077.5 million
during the years ended December 31,
2016
,
2015
and
2014
, respectively, primarily as a result of our capital expenditures for acquisition, drilling and development costs. The increase in cash used in investing activities for the year ended December 31,
2016
as compared to the year ended December 31,
2015
was primarily attributable to an increase in cash used for acquisitions year over year, primarily due to the Williston Basin Acquisition in 2016, partially offset by a
48%
decrease in cash capital expenditures for the development of our properties as a result of lower commodity prices. Net cash used in investing activities during the year ended December 31, 2016 was primarily attributable to
$781.5 million
for acquisitions,
$426.3 million
in other capital expenditures for the development of our properties, including E&P capital, the natural gas processing plant and other OMS infrastructure, partially offset by
$122.0 million
for derivative settlements received as a result of lower crude oil prices. Net cash used in investing activities during the year ended December 31, 2015 was primarily attributable to $819.8 million in capital expenditures, which were primarily for the development of our properties, including E&P capital, OMS pipelines, salt water disposal wells and natural gas processing plant construction, partially offset by $370.4 million for derivative settlements
received as a result of lower crude oil prices. Net cash used in investing activities during the year ended December 31, 2014 was primarily attributable to $1,354.3 million in capital expenditures for the development of our properties, including E&P capital, OMS pipelines and salt water disposal wells and the addition of a second fracturing fleet for OWS, partially offset by $324.9 million in proceeds from the sale of certain non-operated properties in and around our Sanish position.
Expenditures for the acquisition and development of oil and natural gas properties are the primary use of our capital resources. Our capital expenditures for the years ended December 31,
2016
,
2015
and
2014
are summarized in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Capital expenditures
|
|
|
|
|
|
E&P
|
$
|
208,437
|
|
|
$
|
436,959
|
|
|
$
|
1,399,684
|
|
OMS
|
170,386
|
|
|
96,947
|
|
|
68,939
|
|
OWS
|
680
|
|
|
21,711
|
|
|
37,292
|
|
Other capital expenditures
(1)
|
20,502
|
|
|
25,643
|
|
|
29,440
|
|
Total capital expenditures before acquisitions
|
$
|
400,005
|
|
|
$
|
581,260
|
|
|
$
|
1,535,355
|
|
Acquisitions
|
781,522
|
|
|
28,739
|
|
|
37,238
|
|
Total capital expenditures
(2)
|
$
|
1,181,527
|
|
|
$
|
609,999
|
|
|
$
|
1,572,593
|
|
__________________
|
|
(1)
|
Other capital expenditures include such items as administrative capital and capitalized interest.
|
|
|
(2)
|
Capital expenditures (including acquisitions) reflected in the table above differ from the amounts for capital expenditures and acquisitions of oil and gas properties shown in the statement of cash flows in our consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis.
|
In
2016
, we spent
$1,181.5 million
on capital expenditures, which represented a 94% increase as compared to the
$610.0 million
spent during
2015
. This increase was primarily due to
$781.5 million
for acquisitions in 2016, including the Williston Basin Acquisition. Excluding acquisitions, capital expenditures decreased
31%
as compared to 2015. The decrease was attributable to reduced drilling and completion activity as a result of lower commodity prices in 2016, offset by higher capital expenditures for OMS, primarily related to the natural gas processing plant constructed in our Wild Basin area in North Dakota.
During
2016
, we participated in
64
gross wells (
38.1
net) that were completed and placed on production, and, as operator, we completed and placed on production
57
gross (
37.6
net) of these wells. In addition, as of December 31,
2016
, we had
83
gross operated wells awaiting completion in the Bakken and Three Forks formations. Our land leasing and acquisition activity is focused in and around our existing core consolidated land positions.
As a result of current oil prices, we have increased our planned 2017 capital expenditures as compared to 2016 capital expenditures, excluding acquisitions. We anticipate investing
$605 million
in
2017
as follows:
|
|
|
|
|
|
Budget for the year ended December 31, 2017
|
|
(In thousands)
|
Drilling and completion
|
$
|
410,000
|
|
OMS
|
110,000
|
|
Other
(1)
|
85,000
|
|
Total capital expenditures
|
$
|
605,000
|
|
__________________
|
|
(1)
|
Other capital expenditures include other E&P, capitalized interest, OWS and administrative capital.
|
While we have budgeted
$605 million
for total capital expenditures in
2017
, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Furthermore, if we acquire additional acreage, our capital expenditures may be higher than budgeted. We believe that cash on hand, including cash flows from operating activities, proceeds from cash settlements under our derivative contracts and availability under our revolving credit facility should be sufficient to fund our
2017
capital expenditure budget. However, because the operated wells funded by our
2017
drilling plan represent only a small percentage of our potential drilling
locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of potential drilling locations should we elect to do so.
Our capital budget may further be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil prices decline for an extended period of time, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. We actively review acquisition opportunities on an ongoing basis. Our ability to make significant acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.
Cash flows provided by financing activities
Net cash provided by financing activities was
$844.3 million
,
$83.3 million
and
$158.8 million
for the years ended December 31,
2016
,
2015
and
2014
, respectively. For the year ended
December 31, 2016
, cash sourced through financing activities was provided by net proceeds from the issuance of our common stock, the issuance of our Senior Convertible Notes, and the borrowings under our revolving credit facility, partially offset by the repurchase of a portion of our Senior Notes. For the year ended December 31, 2015, cash sourced through financing activities was provided by net proceeds from the issuance of our common stock, partially offset by net repayments on our revolving credit facility. For the year ended December 31, 2014, cash sourced through financing activities was provided by borrowings under our revolving credit facility.
Sale of common stock.
On February 2, 2016, we completed a public offering of 39,100,000 shares of our common stock (including 5,100,000 shares issued pursuant to the underwriters’ option to purchase additional common stock) at a purchase price of $4.685 per share. We used the net proceeds from the offering of $182.8 million, after deducting underwriting discounts and commissions and offering expenses, for general corporate purposes.
On October 21, 2016, we completed a public offering of 55,200,000 shares of our common stock (including 7,200,000 shares issued pursuant to the underwriters’ option to purchase additional common stock) at a purchase price to the public of $10.80 per share. We used the net proceeds of $584.0 million, after deducting underwriting discounts and commissions and estimated offering expenses, to fund a portion of the Williston Basin Acquisition.
Senior secured revolving line of credit.
We have a revolving credit facility (the “Credit Facility”) with an overall senior secured line of credit of $2,500.0 million as of December 31,
2016
. The Credit Facility is restricted to the borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year. The maturity date of the Credit Facility is April 13, 2020, provided that the 7.25% senior unsecured notes due February 2019 (the “2019 Notes”) are retired or refinanced 90 days prior to their maturity date. On February 23, 2016, the lenders under the Credit Facility (the “Lenders”) completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2016, resulting in a decrease in the borrowing base and aggregate elected commitment from $1,525.0 million to $1,150.0 million. On October 14, 2016, the borrowing base and aggregate elected commitment were reaffirmed at $1,150.0 million as a result of the semi-annual redetermination of the borrowing base scheduled for October 1, 2016. The next redetermination of the borrowing base is scheduled for April 1, 2017.
As of December 31,
2016
, we had
$363.0 million
of borrowings at a weighted average interest rate of
2.5%
and
$12.3 million
of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing base committed capacity of
$774.7 million
. As of December 31, 2015, we had $138.0 million of borrowings at a weighted average interest rate of 1.9% and $5.2 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing base committed capacity of $1,381.8 million.
The Credit Facility contains covenants that include, among others:
|
|
•
|
a prohibition against incurring debt, subject to permitted exceptions;
|
|
|
•
|
a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;
|
|
|
•
|
a prohibition against making investments, loans and advances, subject to permitted exceptions;
|
|
|
•
|
restrictions on creating liens and leases on our assets and our subsidiaries, subject to permitted exceptions;
|
|
|
•
|
restrictions on merging and selling assets outside the ordinary course of business;
|
|
|
•
|
restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;
|
|
|
•
|
a provision limiting oil and natural gas derivative financial instruments;
|
|
|
•
|
a requirement that we maintain a ratio of consolidated EBITDAX (as defined in the Credit Facility) to consolidated Interest Expense (as defined in the Credit Facility) of no less than 2.5 to 1.0 for the four quarters ended on the last day of each quarter; and
|
|
|
•
|
a requirement that we maintain a Current Ratio (as defined in the Credit Facility) of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the Credit Facility) to consolidated current liabilities (with exclusions as described in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter.
|
The Credit Facility contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable. We were in compliance with the financial covenants of the Credit Facility as of December 31,
2016
and
2015
. As of December 31,
2016
, our consolidated EBITDAX was $500.3 million and our consolidated Interest Expense was $144.7 million, resulting in a ratio of 3.5 as compared to a minimum required ratio of 2.5. In addition, as of December 31,
2016
, our consolidated current assets and consolidated current liabilities (as described above) were $1,012.9 million and $320.6 million, respectively, resulting in a Current Ratio of 3.2 as compared to a minimum required ratio of 1.0. Given the possible fluctuation in commodity prices, we continue to closely monitor our financial covenants and do not anticipate a covenant violation in the next twelve months.
Senior unsecured notes.
As of December 31, 2016, our long-term debt includes outstanding senior unsecured note obligations of $1,753.0 million for senior unsecured notes (the “Senior Notes”), including $54.3 million of the 2019 Notes, $395.5 million of 6.5% senior unsecured notes due November 1, 2021 (the “2021 Notes”), $937.0 million of 6.875% senior unsecured notes due March 15, 2022 (the “2022 Notes”) and $366.1 million of 6.875% senior unsecured notes due January 15, 2023 (the “2023 Notes”).
Prior to certain dates, we have the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The 2019 Notes are currently redeemable for cash at a redemption price equal to par plus accrued and unpaid interest to the redemption date. We may from time to time seek to retire or purchase our outstanding Senior Notes through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
The indentures governing the Senior Notes restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when our Senior Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and we will cease to be subject to such covenants.
Repurchases of senior unsecured notes.
As a result of the Tender Offers, we repurchased an aggregate principal amount of
$362.4 million
of the outstanding Senior Notes, consisting of
$344.7 million
principal amount of the 2019 Notes,
$2.2 million
principal amount of the 2021 Notes,
$3.4 million
principal amount of the 2022 Notes and
$12.1 million
principal amount of the 2023 Notes, for an aggregate cost of
$371.4 million
, including accrued interest and fees.
In addition to the Tender Offers, we repurchased an aggregate principal amount of
$84.6 million
of the outstanding Senior Notes, consisting of
$1.0 million
principal amount of the 2019 Notes,
$2.3 million
principal amount of the 2021 Notes,
$59.5 million
principal amount of the 2022 Notes and
$21.8 million
principal amount of the 2023 Notes, for an aggregate cost of
$64.5 million
, including accrued interest and fees, during the year ended
December 31, 2016
.
For the year ended December 31, 2016, the Company recognized a pre-tax gain of
$4.7 million
related to these repurchases, including the Tender Offers, which were net of unamortized deferred financing costs write-offs of
$6.4 million
, and are reflected in gain on extinguishment of debt in the Company’s Consolidated Statement of Operations.
Senior unsecured convertible notes.
In September 2016, we issued
$300.0 million
of
2.625%
Senior Convertible Notes due September 2023, which resulted in aggregate net proceeds to us of
$291.9 million
, after deducting underwriting discounts and commissions and estimated offering expenses. We used the proceeds from the Senior Convertible Notes to fund the repurchase of certain outstanding Senior Notes through the Tender Offers. The Senior Convertible Notes will mature on September 15, 2023 unless earlier converted in accordance with their terms.
We have the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at out election. Our intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending on September 30, 2016 (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “Measurement Period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the Measurement Period is less than 98% of the product of the last reported sale price of our common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding the September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of our common stock per $1,000 principal amount of the notes, which is equivalent to an initial conversion price of approximately $13.10. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, we will increase the conversion rate for a holder who elects to convert the Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of December 31, 2016, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met.
Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by our material subsidiaries.
Obligations and commitments
We have the following contractual obligations and commitments as of December 31,
2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by period
|
Contractual obligations
|
Total
|
|
Within 1
year
|
|
1-3 years
|
|
3-5 years
|
|
More than
5 years
|
|
(In thousands)
|
Senior unsecured notes
(1)
|
$
|
2,052,950
|
|
|
$
|
—
|
|
|
$
|
54,275
|
|
|
$
|
395,501
|
|
|
$
|
1,603,174
|
|
Interest payments on senior unsecured notes
(1)
|
724,635
|
|
|
127,004
|
|
|
252,265
|
|
|
247,066
|
|
|
98,300
|
|
Borrowings under revolving credit facility
(1)
|
363,000
|
|
|
—
|
|
|
—
|
|
|
363,000
|
|
|
—
|
|
Interest payments on borrowings under revolving credit facility
(1)
|
766
|
|
|
766
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Asset retirement obligations
(2)
|
49,687
|
|
|
702
|
|
|
3,169
|
|
|
647
|
|
|
45,169
|
|
Operating leases
(3)
|
19,186
|
|
|
5,530
|
|
|
9,921
|
|
|
3,735
|
|
|
—
|
|
Volume commitment agreements
(3)
|
472,236
|
|
|
33,103
|
|
|
121,159
|
|
|
123,745
|
|
|
194,229
|
|
Total contractual cash obligations
|
$
|
3,716,791
|
|
|
$
|
168,036
|
|
|
$
|
457,489
|
|
|
$
|
1,150,394
|
|
|
$
|
1,940,872
|
|
__________________
|
|
(1)
|
See Note 8 to our audited consolidated financial statements for a description of our senior unsecured notes, revolving credit facility and related interest payments. As of December 31,
2016
, we had
$363.0 million
of borrowings and
$12.3 million
of outstanding letters of credit issued under our Credit Facility.
|
|
|
(2)
|
Amounts represent the present value of estimated costs expected to be incurred in the future to plug, abandon and remediate our oil and gas properties and salt water disposal wells at the end of their productive lives. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 9 to our audited consolidated financial statements.
|
|
|
(3)
|
See Note 16 to our audited consolidated financial statements for a description of our operating leases and volume commitment agreements.
|
Critical accounting policies and estimates
The discussion and analysis of our financial condition and results of operations are based upon our audited consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and
expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments used in preparation of our consolidated financial statements below. See Note 2 to our audited consolidated financial statements for a discussion of additional accounting policies and estimates made by management.
Method of accounting for oil and natural gas properties
Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.
The provision for DD&A of oil and natural gas properties is calculated using the unit-of-production method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.
Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate in which case a gain or loss is recognized currently.
Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.
Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in our Consolidated Statement of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
Oil and natural gas reserve quantities and standardized measure of future net revenue
Our independent reserve engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the SEC rules allow us to disclose proved, probable and possible reserves, we have elected to disclose only proved reserves in this Annual Report on Form 10-K. The SEC’s rules define proved reserves as the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our independent reserve engineers and technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each field. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
Revenue recognition
Oil and gas revenue from our interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of our production is sold to purchasers under short-term (less than twelve month) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it is produced at various locations. As a result, we maintain a minimum amount of product inventory in storage.
Midstream revenues consist primarily of revenues from salt water pipeline transport, salt water disposal, fresh water sales, natural gas gathering and processing and crude oil gathering for OPNA’s operated wells. OWS provides well services and sells well completion products and equipment rentals primarily to OPNA. Midstream and well services revenue is recognized when services have been performed or related volumes or products have been delivered. The revenues related to OPNA’s working interests are eliminated in consolidation, and only the revenues related to other working interest owners in OPNA’s wells are included in our Consolidated Statement of Operations.
Impairment of proved properties
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved oil and natural gas properties will be recorded. Please see “Overview” for a discussion of potential future impairment charges.
Impairment of unproved properties
The assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage.
We recognize impairment expense for unproved properties at the time when the lease term has expired or sooner based on management’s periodic assessments. We consider the following factors in our assessment of the impairment of unproved properties:
|
|
•
|
the remaining amount of unexpired term under our leases;
|
|
|
•
|
our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;
|
|
|
•
|
our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;
|
|
|
•
|
our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and
|
|
|
•
|
our evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations by us or by other operators in areas adjacent to or near our unproved properties.
|
Business combinations
We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.
We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of oil and natural gas properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties.
Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Asset retirement obligations
We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The asset retirement obligation (“ARO”) represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period, and the capitalized costs are amortized on the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in our Consolidated Statement of Operations.
Some of our midstream assets, including certain pipelines and our natural gas processing plant, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities, when the assets are abandoned. We are not able to reasonably estimate the fair value of the asset retirement obligations for these assets because the settlement dates are indeterminable given our expected continued use of the assets with proper maintenance. We will record asset retirement obligations for these assets in the periods in which the settlement dates are reasonably determinable.
We determine the ARO by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future revisions, which could result in an increase to the existing ARO liability and could ultimately result in a higher potential impact on our operations and cash flows for settlement charges. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Derivatives
We record all derivative instruments on the Consolidated Balance Sheet as either assets or liabilities measured at their estimated fair value. The significant inputs used to estimate fair value are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. We have not designated any derivative instruments as hedges for accounting purposes, and we do not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported under other income (expense) in our Consolidated Statement of Operations. Our cash flow is only impacted when the actual settlements under the
derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on our derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in our Consolidated Statement of Cash Flows.
Stock-based compensation
Restricted stock awards.
We recognize compensation expense for all restricted stock awards made to employees and directors. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the requisite service period, which is generally the vesting period. The fair value of restricted stock grants is based on the value of our common stock on the date of grant. Assumptions regarding forfeiture rates are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized. Stock-based compensation expense recorded for restricted stock awards is included in general and administrative expenses on our Consolidated Statement of Operations.
Performance share units.
We recognize compensation expense for our performance share units (“PSUs”) granted to our officers. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the performance period, which is generally the vesting period. The fair value of the PSUs is based on the calculation derived from a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probable assessment (see Note 11 to our audited consolidated financial statements for a description of the inputs used in this model). Stock-based compensation expense recorded for PSUs is included in general and administrative expenses on our Consolidated Statement of Operations.
Income taxes
Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.
We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.
Recent accounting pronouncements
Revenue recognition.
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09,
Revenue from Contracts with Customers
(“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14,
Deferral of the Effective Date
(“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.
Inventory.
In July 2015, the FASB issued Accounting Standards Update No. 2015-11,
Simplifying the Measurement of Inventory
(“ASU 2015-11”). ASU 2015-11 changes the inventory measurement principle from lower of cost or market to lower of cost and net realizable value for entities using the first-in, first-out or average cost methods. ASU 2015-11 is effective for fiscal
years beginning after December 15, 2016, including interim periods within those years. We do not expect the adoption of this guidance to have a material impact on our financial position, cash flows or results of operations.
Financial instruments.
In January 2016, the FASB issued Accounting Standards Update No. 2016-01,
Recognition and Measurement of Financial Assets and Financial Liabilities
(“ASU 2016-01”), which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.
Leases.
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”), which requires a lessee to recognize lease payment obligations and a corresponding right-of-use asset to be measured at fair value on the balance sheet. ASU 2016-02 also requires certain qualitative and quantitative disclosures about the amount, timing and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.
Embedded derivatives.
In March 2016, the FASB issued Accounting Standards Update No. 2016-06,
Contingent Put and Call Options in Debt Instruments
(“ASU 2016-06”), which clarifies what steps are required when assessing whether the economic characteristics and risks of call (put) options are clearly and closely related to the economic characteristics and risks of their debt hosts, which is one of the criteria for bifurcating an embedded derivative. ASU 2016-06 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. We do not expect the adoption of this guidance to have a material impact on our financial position, cash flows or results of operations.
Stock-based compensation.
In March 2016, the FASB issued Accounting Standards Update No. 2016-09,
Improvements to Employee Share-Based Payment Accounting
(“ASU 2016-09”), which updates several aspects of the accounting for share-based payment transactions, including recognition of excess tax benefits and deficiencies, the classification of those excess tax benefits on the statement of cash flows, an accounting policy election for forfeitures, the amount an employer can withhold to cover income taxes and still qualify for equity classification and the classification of those taxes paid on the statement of cash flows. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. We will elect to remove forfeiture rates and record a cumulative-effect adjustment to equity at the beginning of 2017 when the guidance is adopted and do not expect the adoption of this guidance to have a material impact on our cash flows or results of operations.
Statement of cash flows.
In August 2016, the FASB issued Accounting Standards Update No. 2016-15,
Statement of Cash Flows
(“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are
classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our statement of cash flows.
Business combinations.
In January 2017, the FASB issued Accounting Standards Update No. 2017-01,
Clarifying the Definition of a Business
(“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31,
2016
,
2015
and
2014
. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy, and in the past, we have tended to experience inflationary pressure on the cost of midstream and oilfield services and equipment as increasing oil and natural gas prices increased drilling activity in our areas of operations. In
2016
and
2015
, we experienced service cost reductions as a result of lower oil prices and decreased drilling activity in the Williston Basin. We expect service costs to increase in 2017 due to higher demand resulting from the recent improvement in oil prices.
Off-balance sheet arrangements
Currently, we do not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our
consolidated financial statements in accordance with GAAP. See “Obligations and commitments” above and Note 16 to our audited consolidated financial statements for a description of our commitments and contingencies.
Non-GAAP Financial Measures
Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) Per Share are supplemental non-GAAP financial measures that are used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. These non-GAAP measures should not be considered in isolation or as a substitute for interest expense, net income (loss), operating income (loss), net cash provided by (used in) operating activities, earnings (loss) per share or any other measures prepared under GAAP. Because Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) Per Share exclude some but not all items that affect net income (loss) and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies.
Cash Interest
We define Cash Interest as interest expense plus capitalized interest less amortization and write-offs of deferred financing costs and debt discounts included in interest expense. Cash Interest is not a measure of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on our debt, excluding non-cash amortization, and our ability to maintain compliance with our debt covenants.
The following table presents a reconciliation of the GAAP financial measure of interest expense to the non-GAAP financial measure of Cash Interest for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Interest Expense
|
$
|
140,305
|
|
|
$
|
149,648
|
|
|
$
|
158,390
|
|
Capitalized interest
|
16,848
|
|
|
18,582
|
|
|
8,850
|
|
Amortization of deferred financing costs
|
(9,757
|
)
|
|
(7,238
|
)
|
|
(6,437
|
)
|
Amortization of debt discount
|
(2,709
|
)
|
|
—
|
|
|
—
|
|
Cash Interest
|
$
|
144,687
|
|
|
$
|
160,992
|
|
|
$
|
160,803
|
|
Adjusted EBITDA and Free Cash Flow
We define Adjusted EBITDA as earnings (loss) before interest expense, income taxes, DD&A, exploration expenses and other similar non-cash or nonrecurring charges. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of Adjusted EBITDA provides useful additional information to investors and analysts for assessing our results of operations, financial performance and our ability to generate cash from our business operations without regard to our financing methods or capital structure coupled with our ability to maintain compliance with our debt covenants.
We define Free Cash Flow as Adjusted EBITDA less Cash Interest and capital expenditures, excluding capitalized interest. Free Cash Flow is not a measure of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of Free Cash Flow provides useful additional information to investors and analysts for assessing our financial performance as compared to our peers and our ability to generate cash from our business operations after interest and capital spending. In addition, Free Cash Flow excludes changes in operating assets and liabilities that relate to the timing of cash receipts and disbursements, which we may not control, and changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.
The following table presents reconciliations of the GAAP financial measures of net income (loss) and net cash provided by (used in) operating activities to the non-GAAP financial measures of Adjusted EBITDA and Free Cash Flow for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Net income (loss)
|
$
|
(243,016
|
)
|
|
$
|
(40,248
|
)
|
|
$
|
506,877
|
|
(Gain) loss on sale of properties
|
1,303
|
|
|
—
|
|
|
(186,999
|
)
|
Gain on extinguishment of debt
|
(4,741
|
)
|
|
—
|
|
|
—
|
|
Net (gain) loss on derivative instruments
|
105,317
|
|
|
(210,376
|
)
|
|
(327,011
|
)
|
Derivative settlements
(1)
|
121,977
|
|
|
370,410
|
|
|
6,774
|
|
Interest expense, net of capitalized interest
|
140,305
|
|
|
149,648
|
|
|
158,390
|
|
Depreciation, depletion and amortization
|
476,331
|
|
|
485,322
|
|
|
412,334
|
|
Impairment
|
4,684
|
|
|
46,109
|
|
|
47,238
|
|
Exploration expenses
|
1,785
|
|
|
2,369
|
|
|
3,064
|
|
Rig termination
|
—
|
|
|
3,895
|
|
|
—
|
|
Stock-based compensation expenses
|
24,103
|
|
|
25,272
|
|
|
21,302
|
|
Income tax (benefit) expense
|
(128,538
|
)
|
|
(16,123
|
)
|
|
307,591
|
|
Other non-cash adjustments
|
790
|
|
|
3,956
|
|
|
3,284
|
|
Adjusted EBITDA
|
500,300
|
|
|
820,234
|
|
|
952,844
|
|
Cash Interest
|
(144,687
|
)
|
|
(160,992
|
)
|
|
(160,803
|
)
|
Capital expenditures
(2)
|
(1,181,527
|
)
|
|
(610,000
|
)
|
|
(1,572,593
|
)
|
Capitalized interest
|
16,848
|
|
|
18,582
|
|
|
8,850
|
|
Free Cash Flow
|
$
|
(809,066
|
)
|
|
$
|
67,824
|
|
|
$
|
(771,702
|
)
|
|
|
|
|
|
|
Net cash provided by operating activities
|
$
|
228,018
|
|
|
$
|
359,815
|
|
|
$
|
872,516
|
|
Derivative settlements
(1)
|
121,977
|
|
|
370,410
|
|
|
6,774
|
|
Interest expense, net of capitalized interest
|
140,305
|
|
|
149,648
|
|
|
158,390
|
|
Exploration expenses
|
1,785
|
|
|
2,369
|
|
|
3,064
|
|
Rig termination
|
—
|
|
|
3,895
|
|
|
—
|
|
Deferred financing costs amortization and other
|
(14,334
|
)
|
|
(12,299
|
)
|
|
(11,028
|
)
|
Current tax (benefit) expense
|
—
|
|
|
(9
|
)
|
|
134
|
|
Changes in working capital
|
21,759
|
|
|
(57,551
|
)
|
|
(80,290
|
)
|
Other non-cash adjustments
|
790
|
|
|
3,956
|
|
|
3,284
|
|
Adjusted EBITDA
|
500,300
|
|
|
820,234
|
|
|
952,844
|
|
Cash Interest
|
(144,687
|
)
|
|
(160,992
|
)
|
|
(160,803
|
)
|
Capital expenditures
(2)
|
(1,181,527
|
)
|
|
(610,000
|
)
|
|
(1,572,593
|
)
|
Capitalized interest
|
16,848
|
|
|
18,582
|
|
|
8,850
|
|
Free Cash Flow
|
$
|
(809,066
|
)
|
|
$
|
67,824
|
|
|
$
|
(771,702
|
)
|
____________________
|
|
(1)
|
Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
|
|
|
(2)
|
Capital expenditures (including acquisitions) reflected in the table above differ from the amounts for capital expenditures and acquisitions of oil and gas properties shown in the statement of cash flows in our consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis. Acquisitions totaled $781.5 million, $28.7 million and $37.2 million for the years ended December 31, 2016, 2015 and 2014, respectively.
|
The following tables present reconciliations of the GAAP financial measure of income (loss) before income taxes to the non-GAAP financial measure of Adjusted EBITDA for our three reportable business segments on a gross basis for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Production
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Income (loss) before income taxes
|
$
|
(436,469
|
)
|
|
$
|
(118,970
|
)
|
|
$
|
779,591
|
|
(Gain) loss on sale of properties
|
1,661
|
|
|
—
|
|
|
(186,999
|
)
|
Gain on extinguishment of debt
|
(4,741
|
)
|
|
—
|
|
|
—
|
|
Net (gain) loss on derivative instruments
|
105,317
|
|
|
(210,376
|
)
|
|
(327,011
|
)
|
Derivative settlements
(1)
|
121,977
|
|
|
370,410
|
|
|
6,774
|
|
Interest expense, net of capitalized interest
|
140,305
|
|
|
149,648
|
|
|
158,390
|
|
Depreciation, depletion and amortization
|
467,894
|
|
|
479,693
|
|
|
406,960
|
|
Impairment
|
2,253
|
|
|
46,109
|
|
|
47,238
|
|
Exploration expenses
|
1,785
|
|
|
2,369
|
|
|
3,064
|
|
Rig termination
|
—
|
|
|
3,895
|
|
|
—
|
|
Stock-based compensation expenses
|
23,346
|
|
|
24,762
|
|
|
20,701
|
|
Other non-cash adjustments
|
718
|
|
|
3,719
|
|
|
2,314
|
|
Adjusted EBITDA
|
$
|
424,046
|
|
|
$
|
751,259
|
|
|
$
|
911,022
|
|
____________________
|
|
(1)
|
Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream Services
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Income before income taxes
|
$
|
68,394
|
|
|
$
|
59,867
|
|
|
$
|
22,730
|
|
Gain on sale of properties
|
(358
|
)
|
|
—
|
|
|
—
|
|
Depreciation, depletion and amortization
|
8,525
|
|
|
5,764
|
|
|
3,744
|
|
Impairment
|
2,431
|
|
|
—
|
|
|
—
|
|
Stock-based compensation expenses
|
911
|
|
|
692
|
|
|
—
|
|
Other non-cash adjustments
|
10
|
|
|
—
|
|
|
—
|
|
Adjusted EBITDA
|
$
|
79,913
|
|
|
$
|
66,323
|
|
|
$
|
26,474
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well Services
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Income before income taxes
|
$
|
3,471
|
|
|
$
|
49,197
|
|
|
$
|
70,953
|
|
Depreciation, depletion and amortization
|
14,892
|
|
|
19,073
|
|
|
14,080
|
|
Stock-based compensation expenses
|
1,515
|
|
|
1,952
|
|
|
1,658
|
|
Other non-cash adjustments
|
62
|
|
|
237
|
|
|
970
|
|
Adjusted EBITDA
|
$
|
19,940
|
|
|
$
|
70,459
|
|
|
$
|
87,661
|
|
Adjusted Net Income and Adjusted Diluted Earnings Per Share
We define Adjusted Net Income (Loss) as net income (loss) after adjusting first for (1) the impact of certain non-cash items, including non-cash changes in the fair value of derivative instruments, impairment and other similar non-cash charges, and non-recurring items, and then (2) the non-cash and non-recurring items’ impact on taxes based on our effective tax rate applicable to those adjusting items in the same period. Adjusted Net Income (Loss) is not a measure of net income (loss) as determined by GAAP. We define Adjusted Diluted Earnings (Loss) Per Share as Adjusted Net Income (Loss) divided by
diluted weighted average shares outstanding. Management believes that the presentation of Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) Per Share provides useful additional information to investors and analysts for evaluating our operational trends and performance in comparison to our peers. This measure is more comparable to earnings estimates provided by securities analysts, and charges or amounts excluded cannot be reasonably estimated and are excluded from guidance provided by the Company.
The following table presents reconciliations of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted Net Income (Loss) and the GAAP financial measure of diluted earnings (loss) per share to the non-GAAP financial measure of Adjusted Diluted Earnings Per Share for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands, except per share data)
|
Net income (loss)
|
$
|
(243,016
|
)
|
|
$
|
(40,248
|
)
|
|
$
|
506,877
|
|
(Gain) loss on sale of properties
|
1,303
|
|
|
—
|
|
|
(186,999
|
)
|
Gain on extinguishment of debt
|
(4,741
|
)
|
|
—
|
|
|
—
|
|
Net (gain) loss on derivative instruments
|
105,317
|
|
|
(210,376
|
)
|
|
(327,011
|
)
|
Derivative settlements
(1)
|
121,977
|
|
|
370,410
|
|
|
6,774
|
|
Impairment
|
4,684
|
|
|
46,109
|
|
|
47,238
|
|
Rig termination
|
—
|
|
|
3,895
|
|
|
—
|
|
Amortization of deferred financing costs
(2)
|
9,757
|
|
|
7,238
|
|
|
6,437
|
|
Amortization of debt discount
|
2,709
|
|
|
—
|
|
|
—
|
|
Other non-cash adjustments
|
790
|
|
|
3,956
|
|
|
3,284
|
|
Tax impact
(3)
|
(90,480
|
)
|
|
(82,697
|
)
|
|
170,205
|
|
Adjusted Net Income (Loss)
|
$
|
(91,700
|
)
|
|
$
|
98,287
|
|
|
$
|
226,805
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share
|
$
|
(1.32
|
)
|
|
$
|
(0.31
|
)
|
|
$
|
5.05
|
|
(Gain) loss on sale of properties
|
0.01
|
|
|
—
|
|
|
(1.86
|
)
|
Gain on extinguishment of debt
|
(0.03
|
)
|
|
—
|
|
|
—
|
|
Net (gain) loss on derivative instruments
|
0.57
|
|
|
(1.62
|
)
|
|
(3.26
|
)
|
Derivative settlements
(1)
|
0.66
|
|
|
2.85
|
|
|
0.07
|
|
Impairment
|
0.03
|
|
|
0.35
|
|
|
0.47
|
|
Rig termination
|
—
|
|
|
0.03
|
|
|
—
|
|
Amortization of deferred financing costs
(2)
|
0.05
|
|
|
0.06
|
|
|
0.06
|
|
Amortization of debt discount
|
0.01
|
|
|
—
|
|
|
—
|
|
Other non-cash adjustments
|
—
|
|
|
0.03
|
|
|
0.03
|
|
Tax impact
(3)
|
(0.48
|
)
|
|
(0.64
|
)
|
|
1.70
|
|
Adjusted Diluted Earnings (Loss) Per Share
|
$
|
(0.50
|
)
|
|
$
|
0.75
|
|
|
$
|
2.26
|
|
|
|
|
|
|
|
Diluted weighted average shares outstanding
|
183,615
|
|
|
130,186
|
|
|
100,365
|
|
|
|
|
|
|
|
Effective tax rate applicable to adjustment items
|
37.4
|
%
|
|
37.4
|
%
|
|
37.8
|
%
|
____________________
|
|
(1)
|
Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
|
|
|
(2)
|
As of December 31, 2016, Adjusted Net Income (Loss) includes the non-cash adjustment for amortization of deferred financing costs. Comparative periods have been conformed. The amortization of deferred financing costs is included in interest expense on our Consolidated Statement of Operations.
|
|
|
(3)
|
The tax impact is computed utilizing our effective tax rate applicable to the adjustments for certain non-cash and non-recurring items.
|
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management, including the use of derivative instruments.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, natural gas liquids, and oil prices, and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view
and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.
Commodity price exposure risk.
We are exposed to market risk as the prices of oil and natural gas fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a significant portion of our future production.
We utilize derivative financial instruments to manage risks related to changes in oil and natural gas prices. Our crude oil and natural gas contracts will settle monthly based on the average WTI and the average NYMEX Henry Hub natural gas index price, respectively. As of December 31,
2016
, we utilized swaps and two-way and three-way costless collar options to reduce the volatility of oil and natural gas prices on a significant portion of its future expected oil and natural gas production. A swap is a sold call and a purchased put established at the same price (both ceiling and floor), which we will receive for the volumes under contract. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract.
We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement.
The following is a summary of our derivative contracts as of December 31,
2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
Settlement
Period
|
|
Derivative
Instrument
|
|
Volumes
|
|
Weighted Average Prices
|
|
Fair Value
Asset
(Liability)
|
|
|
|
|
Swap
|
|
Sub-Floor
|
|
Floor
|
|
Ceiling
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
Crude oil
|
|
2017
|
|
Swaps
|
|
7,369,000
|
|
Bbl
|
|
$
|
49.48
|
|
|
|
|
|
|
|
|
|
|
$
|
(44,830
|
)
|
Crude oil
|
|
2017
|
|
Two-way collar
|
|
2,672,000
|
|
Bbl
|
|
|
|
|
|
$
|
46.25
|
|
|
$
|
54.37
|
|
|
(10,674
|
)
|
Crude oil
|
|
2017
|
|
Three-way collar
|
|
2,004,000
|
|
Bbl
|
|
|
|
$
|
31.67
|
|
|
$
|
45.83
|
|
|
$
|
59.94
|
|
|
(3,077
|
)
|
Crude oil
|
|
2018
|
|
Swaps
|
|
2,440,000
|
|
Bbl
|
|
$
|
52.93
|
|
|
|
|
|
|
|
|
(8,475
|
)
|
Crude oil
|
|
2018
|
|
Two-way collar
|
|
582,000
|
|
Bbl
|
|
|
|
|
|
$
|
48.40
|
|
|
$
|
55.13
|
|
|
(2,101
|
)
|
Crude oil
|
|
2018
|
|
Three-way collar
|
|
186,000
|
|
Bbl
|
|
|
|
$
|
31.67
|
|
|
$
|
45.83
|
|
|
$
|
59.94
|
|
|
(446
|
)
|
Crude oil
|
|
2019
|
|
Swaps
|
|
155,000
|
|
Bbl
|
|
$
|
53.88
|
|
|
|
|
|
|
|
|
(332
|
)
|
Crude oil
|
|
2019
|
|
Two-way collar
|
|
31,000
|
|
Bbl
|
|
|
|
|
|
$
|
50.00
|
|
|
$
|
55.70
|
|
|
(86
|
)
|
Natural gas
|
|
2017
|
|
Swaps
|
|
5,475,000
|
|
MMBtu
|
|
$
|
3.32
|
|
|
|
|
|
|
|
|
(1,697
|
)
|
Natural gas
|
|
2018
|
|
Swaps
|
|
730,000
|
|
MMBtu
|
|
$
|
2.99
|
|
|
|
|
|
|
|
|
(103
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(71,821
|
)
|
A 10% increase in crude oil prices would decrease the fair value of our derivative position by approximately
$75.3 million
, while a 10% decrease in crude oil prices would increase the fair value by approximately
$70.9 million
.
Interest rate risk.
At December 31,
2016
, we had (i)
$54.3 million
of Senior Notes at a fixed cash interest rate of
7.25%
per annum, (ii)
$395.5 million
of Senior Notes at a fixed cash interest rate of
6.5%
per annum, (iii)
$1,303.2 million
of Senior Notes at a fixed cash interest rate of
6.875%
per annum and (iv)
$300.00 million
of Senior Convertible Notes at a fixed cash interest rate of
2.625%
per annum outstanding. At December 31,
2016
, we also had
$363.0 million
of borrowings and
$12.3 million
of outstanding letters of credit issued under our Credit Facility, which were subject to varying rates of interest based on (1) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a LIBOR loan or a domestic bank prime interest rate loan (defined in the Credit Facility as an Alternate Based Rate or “ABR” loan). At December 31,
2016
, the outstanding borrowings under our Credit Facility bore interest at LIBOR plus a
1.5%
margin. We do not currently, but may in the future, utilize interest rate derivatives to alter
interest rate exposure in an attempt to reduce interest rate expense related to debt issued under our Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Counterparty and customer credit risk.
Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the year ended December 31,
2016
, we recorded bad debt expense of $1.8 million related to our joint interest receivables. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
While we do not require all of our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, their historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. Several of our significant customers for oil and natural gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.
As permitted under our investments policy, we may purchase commercial paper instruments from high credit quality counterparties. These counterparties may include issuers in a variety of industries including the domestic and foreign financial sector. This risk is managed by our investment policy including minimum credit ratings thresholds and maximum counterparty exposure values. Although we do not anticipate any of our commercial paper issuers failing to pay us upon maturity, we take a risk in purchasing the commercial paper instruments available in the marketplace. If an issuer fails to repay us at maturity from commercial paper proceeds, it could take a significant amount of time to recover a portion of or all of the assets originally invested. Our commercial paper balance was
$36,000
at December 31,
2016
.
In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions. Most of the counterparties on our derivative instruments currently in place are Lenders under our Credit Facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other Lenders under our Credit Facility, which also carry investment grade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. We had a net derivative asset position of
$0.4 million
and a net derivative liability position of
$72.2 million
at December 31,
2016
.
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Oasis Petroleum Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Oasis Petroleum Inc. and its subsidiaries (the “Company”) at December 31,
2016
and
2015
, and the results of their operations and their cash flows for each of the three years in the period ended December 31,
2016
in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31,
2016
, based on criteria established in
Internal Control—Integrated Framework (2013)
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting 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 audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers LLP
Houston, Texas
February 23, 2017
Oasis Petroleum Inc.
Consolidated Balance Sheet
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
(In thousands, except share data)
|
ASSETS
|
|
|
|
Current assets
|
|
|
|
Cash and cash equivalents
|
$
|
11,226
|
|
|
$
|
9,730
|
|
Accounts receivable, net
|
204,335
|
|
|
197,409
|
|
Inventory
|
10,648
|
|
|
11,072
|
|
Prepaid expenses
|
7,623
|
|
|
7,328
|
|
Derivative instruments
|
362
|
|
|
139,697
|
|
Other current assets
|
4,355
|
|
|
50
|
|
Total current assets
|
238,549
|
|
|
365,286
|
|
Property, plant and equipment
|
|
|
|
Oil and gas properties (successful efforts method)
|
7,296,568
|
|
|
6,284,401
|
|
Other property and equipment
|
618,790
|
|
|
443,265
|
|
Less: accumulated depreciation, depletion, amortization and impairment
|
(1,995,791
|
)
|
|
(1,509,424
|
)
|
Total property, plant and equipment, net
|
5,919,567
|
|
|
5,218,242
|
|
Assets held for sale
|
—
|
|
|
26,728
|
|
Derivative instruments
|
—
|
|
|
15,776
|
|
Other assets
|
20,516
|
|
|
23,343
|
|
Total assets
|
$
|
6,178,632
|
|
|
$
|
5,649,375
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
Current liabilities
|
|
|
|
Accounts payable
|
$
|
4,645
|
|
|
$
|
9,983
|
|
Revenues and production taxes payable
|
139,737
|
|
|
132,356
|
|
Accrued liabilities
|
119,173
|
|
|
167,669
|
|
Accrued interest payable
|
39,004
|
|
|
49,413
|
|
Derivative instruments
|
60,469
|
|
|
—
|
|
Advances from joint interest partners
|
7,597
|
|
|
4,647
|
|
Other current liabilities
|
10,490
|
|
|
6,500
|
|
Total current liabilities
|
381,115
|
|
|
370,568
|
|
Long-term debt
|
2,297,214
|
|
|
2,302,584
|
|
Deferred income taxes
|
513,529
|
|
|
608,155
|
|
Asset retirement obligations
|
48,985
|
|
|
35,338
|
|
Liabilities held for sale
|
—
|
|
|
10,228
|
|
Derivative instruments
|
11,714
|
|
|
—
|
|
Other liabilities
|
2,918
|
|
|
3,160
|
|
Total liabilities
|
3,255,475
|
|
|
3,330,033
|
|
Commitments and contingencies (Note 16)
|
|
|
|
|
|
Stockholders’ equity
|
|
|
|
Common stock, $0.01 par value: 450,000,000 and 300,000,000 shares authorized at December 31, 2016 and 2015, respectively; 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016 and 139,583,990 shares issued and 139,076,064 shares outstanding at December 31, 2015
|
2,331
|
|
|
1,376
|
|
Treasury stock, at cost: 856,892 shares and 507,926 shares at December 31, 2016 and 2015, respectively
|
(15,950
|
)
|
|
(13,620
|
)
|
Additional paid-in-capital
|
2,345,271
|
|
|
1,497,065
|
|
Retained earnings
|
591,505
|
|
|
834,521
|
|
Total stockholders’ equity
|
2,923,157
|
|
|
2,319,342
|
|
Total liabilities and stockholders’ equity
|
$
|
6,178,632
|
|
|
$
|
5,649,375
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Oasis Petroleum Inc.
Consolidated Statement of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands, except per share data)
|
Revenues
|
|
|
|
|
|
Oil and gas revenues
|
$
|
635,505
|
|
|
$
|
721,672
|
|
|
$
|
1,304,004
|
|
Midstream revenues
|
35,406
|
|
|
23,769
|
|
|
11,614
|
|
Well services revenues
|
33,754
|
|
|
44,294
|
|
|
74,610
|
|
Total revenues
|
704,665
|
|
|
789,735
|
|
|
1,390,228
|
|
Operating expenses
|
|
|
|
|
|
Lease operating expenses
|
135,444
|
|
|
144,481
|
|
|
169,600
|
|
Midstream operating expenses
|
9,003
|
|
|
6,198
|
|
|
4,647
|
|
Well services operating expenses
|
17,009
|
|
|
21,833
|
|
|
45,605
|
|
Marketing, transportation and gathering expenses
|
40,366
|
|
|
31,610
|
|
|
29,133
|
|
Production taxes
|
56,565
|
|
|
69,584
|
|
|
127,648
|
|
Depreciation, depletion and amortization
|
476,331
|
|
|
485,322
|
|
|
412,334
|
|
Exploration expenses
|
1,785
|
|
|
2,369
|
|
|
3,064
|
|
Rig termination
|
—
|
|
|
3,895
|
|
|
—
|
|
Impairment
|
4,684
|
|
|
46,109
|
|
|
47,238
|
|
General and administrative expenses
|
93,008
|
|
|
92,498
|
|
|
92,306
|
|
Total operating expenses
|
834,195
|
|
|
903,899
|
|
|
931,575
|
|
Gain (loss) on sale of properties
|
(1,303
|
)
|
|
—
|
|
|
186,999
|
|
Operating income (loss)
|
(130,833
|
)
|
|
(114,164
|
)
|
|
645,652
|
|
Other income (expense)
|
|
|
|
|
|
Net gain (loss) on derivative instruments
|
(105,317
|
)
|
|
210,376
|
|
|
327,011
|
|
Interest expense, net of capitalized interest
|
(140,305
|
)
|
|
(149,648
|
)
|
|
(158,390
|
)
|
Gain on extinguishment of debt
|
4,741
|
|
|
—
|
|
|
—
|
|
Other income (expense)
|
160
|
|
|
(2,935
|
)
|
|
195
|
|
Total other income (expense)
|
(240,721
|
)
|
|
57,793
|
|
|
168,816
|
|
Income (loss) before income taxes
|
(371,554
|
)
|
|
(56,371
|
)
|
|
814,468
|
|
Income tax benefit (expense)
|
128,538
|
|
|
16,123
|
|
|
(307,591
|
)
|
Net income (loss)
|
$
|
(243,016
|
)
|
|
$
|
(40,248
|
)
|
|
$
|
506,877
|
|
Earnings (loss) per share:
|
|
|
|
|
|
Basic (Note 13)
|
$
|
(1.32
|
)
|
|
$
|
(0.31
|
)
|
|
$
|
5.09
|
|
Diluted (Note 13)
|
(1.32
|
)
|
|
(0.31
|
)
|
|
5.05
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
Basic (Note 13)
|
183,615
|
|
|
130,186
|
|
|
99,677
|
|
Diluted (Note 13)
|
183,615
|
|
|
130,186
|
|
|
100,365
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Oasis Petroleum Inc.
Consolidated Statement of Changes in Stockholders’ Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
Treasury Stock
|
|
Additional Paid-in-Capital
|
|
Retained
Earnings (Deficit)
|
|
Total
Stockholders’ Equity
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|
|
|
(In thousands)
|
Balance as of December 31, 2013
|
100,699
|
|
|
$
|
996
|
|
|
167
|
|
|
$
|
(5,362
|
)
|
|
$
|
985,023
|
|
|
$
|
367,892
|
|
|
$
|
1,348,549
|
|
Fees (2013 issuance of common stock)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(176
|
)
|
|
—
|
|
|
(176
|
)
|
Stock-based compensation
|
762
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
22,355
|
|
|
—
|
|
|
22,360
|
|
Treasury stock – tax withholdings
|
(119
|
)
|
|
—
|
|
|
119
|
|
|
(5,309
|
)
|
|
—
|
|
|
—
|
|
|
(5,309
|
)
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
506,877
|
|
|
506,877
|
|
Balance as of December 31, 2014
|
101,342
|
|
|
1,001
|
|
|
286
|
|
|
(10,671
|
)
|
|
1,007,202
|
|
|
874,769
|
|
|
1,872,301
|
|
Issuance of common stock
|
36,800
|
|
|
368
|
|
|
—
|
|
|
—
|
|
|
462,465
|
|
|
—
|
|
|
462,833
|
|
Stock-based compensation
|
1,156
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
27,398
|
|
|
—
|
|
|
27,405
|
|
Treasury stock – tax withholdings
|
(222
|
)
|
|
—
|
|
|
222
|
|
|
(2,949
|
)
|
|
—
|
|
|
—
|
|
|
(2,949
|
)
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(40,248
|
)
|
|
(40,248
|
)
|
Balance as of December 31, 2015
|
139,076
|
|
|
1,376
|
|
|
508
|
|
|
(13,620
|
)
|
|
1,497,065
|
|
|
834,521
|
|
|
2,319,342
|
|
Issuance of common stock
|
94,300
|
|
|
943
|
|
|
—
|
|
|
—
|
|
|
765,727
|
|
|
—
|
|
|
766,670
|
|
Stock-based compensation
|
3,317
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
25,759
|
|
|
—
|
|
|
25,771
|
|
Equity component of senior unsecured convertible notes, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56,720
|
|
|
—
|
|
|
56,720
|
|
Treasury stock – tax withholdings
|
(349
|
)
|
|
—
|
|
|
349
|
|
|
(2,330
|
)
|
|
—
|
|
|
—
|
|
|
(2,330
|
)
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(243,016
|
)
|
|
(243,016
|
)
|
Balance as of December 31, 2016
|
236,344
|
|
|
$
|
2,331
|
|
|
857
|
|
|
$
|
(15,950
|
)
|
|
$
|
2,345,271
|
|
|
$
|
591,505
|
|
|
$
|
2,923,157
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Oasis Petroleum Inc.
Consolidated Statement of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Cash flows from operating activities:
|
|
|
|
|
|
Net income (loss)
|
$
|
(243,016
|
)
|
|
$
|
(40,248
|
)
|
|
$
|
506,877
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
Depreciation, depletion and amortization
|
476,331
|
|
|
485,322
|
|
|
412,334
|
|
Gain on extinguishment of debt
|
(4,741
|
)
|
|
—
|
|
|
—
|
|
(Gain) loss on sale of properties
|
1,303
|
|
|
—
|
|
|
(186,999
|
)
|
Impairment
|
4,684
|
|
|
46,109
|
|
|
47,238
|
|
Deferred income taxes
|
(128,538
|
)
|
|
(16,114
|
)
|
|
307,457
|
|
Derivative instruments
|
105,317
|
|
|
(210,376
|
)
|
|
(327,011
|
)
|
Stock-based compensation expenses
|
24,103
|
|
|
25,272
|
|
|
21,302
|
|
Deferred financing costs amortization and other
|
14,334
|
|
|
12,299
|
|
|
11,028
|
|
Working capital and other changes:
|
|
|
|
|
|
Change in accounts receivable, net
|
(11,923
|
)
|
|
108,461
|
|
|
16,702
|
|
Change in inventory
|
254
|
|
|
6,873
|
|
|
(3,776
|
)
|
Change in prepaid expenses
|
(295
|
)
|
|
1,828
|
|
|
(3,199
|
)
|
Change in other current assets
|
(305
|
)
|
|
6,489
|
|
|
(6,135
|
)
|
Change in other assets
|
(151
|
)
|
|
(950
|
)
|
|
114
|
|
Change in accounts payable and accrued liabilities
|
(13,839
|
)
|
|
(71,617
|
)
|
|
76,723
|
|
Change in other current liabilities
|
4,490
|
|
|
6,500
|
|
|
—
|
|
Change in other liabilities
|
10
|
|
|
(33
|
)
|
|
(139
|
)
|
Net cash provided by operating activities
|
228,018
|
|
|
359,815
|
|
|
872,516
|
|
Cash flows from investing activities:
|
|
|
|
|
|
Capital expenditures
|
(426,256
|
)
|
|
(819,847
|
)
|
|
(1,354,281
|
)
|
Acquisitions of oil and gas properties
|
(781,522
|
)
|
|
(28,817
|
)
|
|
(46,247
|
)
|
Proceeds from sale of properties
|
12,333
|
|
|
1,075
|
|
|
324,852
|
|
Costs related to sale of properties
|
(310
|
)
|
|
—
|
|
|
(2,337
|
)
|
Derivative settlements
|
121,977
|
|
|
370,410
|
|
|
6,774
|
|
Advances from joint interest partners
|
2,950
|
|
|
(1,969
|
)
|
|
(6,213
|
)
|
Net cash used in investing activities
|
(1,070,828
|
)
|
|
(479,148
|
)
|
|
(1,077,452
|
)
|
Cash flows from financing activities:
|
|
|
|
|
|
Proceeds from revolving credit facility
|
1,407,000
|
|
|
630,000
|
|
|
620,000
|
|
Principal payments on revolving credit facility
|
(1,182,000
|
)
|
|
(992,000
|
)
|
|
(455,570
|
)
|
Repurchase of senior unsecured notes
|
(435,907
|
)
|
|
—
|
|
|
—
|
|
Proceeds from issuance of senior unsecured convertible notes
|
300,000
|
|
|
—
|
|
|
—
|
|
Deferred financing costs
|
(9,127
|
)
|
|
(14,632
|
)
|
|
(99
|
)
|
Proceeds from sale of common stock
|
766,670
|
|
|
462,833
|
|
|
—
|
|
Purchases of treasury stock
|
(2,330
|
)
|
|
(2,949
|
)
|
|
(5,309
|
)
|
Other
|
—
|
|
|
—
|
|
|
(176
|
)
|
Net cash provided by financing activities
|
844,306
|
|
|
83,252
|
|
|
158,846
|
|
Increase (decrease) in cash and cash equivalents
|
1,496
|
|
|
(36,081
|
)
|
|
(46,090
|
)
|
Cash and cash equivalents:
|
|
|
|
|
|
Beginning of period
|
9,730
|
|
|
45,811
|
|
|
91,901
|
|
End of period
|
$
|
11,226
|
|
|
$
|
9,730
|
|
|
$
|
45,811
|
|
Supplemental cash flow information:
|
|
|
|
|
|
Cash paid for interest, net of capitalized interest
|
$
|
138,248
|
|
|
$
|
145,333
|
|
|
$
|
150,181
|
|
Cash paid for taxes
|
—
|
|
|
—
|
|
|
5,329
|
|
Cash received for income tax refunds
|
5
|
|
|
5,548
|
|
|
—
|
|
Supplemental non-cash transactions:
|
|
|
|
|
|
Change in accrued capital expenditures
|
$
|
(43,415
|
)
|
|
$
|
(260,060
|
)
|
|
$
|
169,710
|
|
Change in asset retirement obligations
|
3,810
|
|
|
3,972
|
|
|
6,182
|
|
Note receivable from divestiture
|
4,000
|
|
|
—
|
|
|
—
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Oasis Petroleum Inc.
Notes to Consolidated Financial Statements
1. Organization and Operations of the Company
Oasis Petroleum Inc. (together with its consolidated subsidiaries, “Oasis” or the “Company”) was originally formed in 2007 and was incorporated pursuant to the laws of the State of Delaware in 2010. The Company is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources in the North Dakota and Montana regions of the Williston Basin. Oasis Petroleum North America LLC (“OPNA”) conducts the Company’s exploration and production activities and owns its proved and unproved oil and natural gas properties. The Company also operates a midstream services business through Oasis Midstream Services LLC (“OMS”) and a well services business through Oasis Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to its primary development and production activities.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements of the Company include the accounts of Oasis and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income.
Use of Estimates
Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.
Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of 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 data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs, and impairment expense.
Risks and Uncertainties
As an oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. As a result of current commodity prices, the Company plans to increase its 2017 capital expenditures, excluding acquisitions, as compared to 2016, while continuing to concentrate its drilling activities in certain areas that are the most economic in the Williston Basin. An extended period of low prices for oil and, to a lesser extent, natural gas could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.
Cash Equivalents
The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such investments with original maturity dates less than 90 days as cash equivalents.
Accounts Receivable
Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-term maturities. The Company’s accounts receivable consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates.
The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability. The Company accrues a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts. At
December 31, 2016
, the Company had an allowance for doubtful accounts of
$1.3 million
.
No
allowance for doubtful accounts was recorded for the year ended
December 31, 2015
.
Inventory
Crude oil inventory includes oil in tank and linefill. Equipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operations and well fracturing equipment. Inventory is stated at the lower of cost or market value with cost determined on an average cost method.
Joint Interest Partner Advances
The Company participates in the drilling of oil and natural gas wells with other working interest partners. Due to the capital intensive nature of oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid. Advances to joint interest partners are included in other current assets on the Company’s Consolidated Balance Sheet.
Property, Plant and Equipment
Proved Oil and Gas Properties
Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.
The provision for DD&A of oil and natural gas properties is calculated using the unit-of-production method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.
Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently.
Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.
The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of
estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.
Unproved Oil and Gas Properties
Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in the Consolidated Statement of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties:
|
|
•
|
the remaining amount of unexpired term under its leases;
|
|
|
•
|
its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;
|
|
|
•
|
its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;
|
|
|
•
|
its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and
|
|
|
•
|
its evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations by the Company or by other operators in areas adjacent to or near the Company’s unproved properties.
|
For sales of entire working interests in unproved properties, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
Capitalized Interest
The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. The Company capitalized
$16.8 million
,
$18.6 million
and
$8.8 million
of interest costs for the years ended
December 31, 2016
,
2015
and
2014
, respectively. These amounts are amortized over the life of the related assets.
Other Property and Equipment
The Company’s salt water disposal facilities, natural gas processing plant, pipelines, buildings, furniture, software, equipment and leasehold improvements are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets. The Company uses estimated lives of
30
years for its salt water disposal facilities, natural gas processing plant and pipelines,
20
years for its buildings,
two
to
seven
years for its furniture, software and equipment and the remaining lease term for its leasehold improvements. The calculation for the straight-line DD&A method for its salt water disposal facilities takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheet with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statement of Operations.
Exploration Expenses
Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred.
Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they
are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought.
Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Beginning of period
|
$
|
2,097
|
|
|
$
|
34,522
|
|
|
$
|
123,215
|
|
Exploratory well cost additions (pending determination of proved reserves)
|
—
|
|
|
51,803
|
|
|
336,344
|
|
Exploratory well cost reclassifications (successful determination of proved reserves)
|
—
|
|
|
(84,228
|
)
|
|
(425,037
|
)
|
Exploratory well dry hole costs (unsuccessful in adding proved reserves)
|
—
|
|
|
—
|
|
|
—
|
|
End of period
|
$
|
2,097
|
|
|
$
|
2,097
|
|
|
$
|
34,522
|
|
As of December 31,
2016
, the Company had
no
exploratory well costs that were capitalized for a period of greater than one year after the completion of drilling.
Business Combinations
The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.
The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, the Company reviews comparable purchases and sales of oil and natural gas properties within the same regions and uses that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties.
Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Assets Held for Sale
The Company occasionally markets non-core oil and natural gas properties. At the end of each reporting period, the Company evaluates the properties being marketed to determine whether any should be reclassified as held-for-sale. The held-for-sale criteria include: management commits to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held-for-sale on the Company’s Consolidated Balance Sheet and measured at the lower of their carrying amount or estimated fair value less costs to sell. DD&A expense is not recorded on assets to be divested once they are classified as held for sale.
Deferred Financing Costs
The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the Company’s Consolidated Statement of Operations. The deferred financing costs related to the Company’s senior unsecured notes and revolving credit facility are included in long-term debt and other assets, respectively, on the Company’s Consolidated Balance Sheet.
Asset Retirement Obligations
In accordance with the Financial Accounting Standard Board’s (“FASB”) authoritative guidance on asset retirement obligations (“ARO”), the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in the Company’s Consolidated Statement of Operations.
Some of the Company’s midstream assets, including certain pipelines and the natural gas processing plant, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities, when the assets are abandoned. The Company is not able to reasonably estimate the fair value of the asset retirement obligations for these assets because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. The Company will record asset retirement obligations for these assets in the periods in which the settlement dates are reasonably determinable.
The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 3 — Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Revenue Recognition
Oil and gas revenue from the Company’s interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of the Company’s production is sold to purchasers under short-term (less than twelve months) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, the Company sells the majority of its production soon after it is produced at various locations. As a result, the Company maintains a minimum amount of product inventory in storage.
Midstream revenues consist of revenues from salt water gathering and disposal services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other midstream services provided by OMS primarily for OPNA’s operated wells. Well services revenues result from well services, product sales and equipment rentals provided by OWS primarily for OPNA’s operated wells. Midstream and well services revenues are recognized when services have been performed or related volumes or products have been delivered. The revenues related to OPNA’s working interests are eliminated in consolidation, and only the revenues related to other working interest owners in OPNA’s wells are included in the Company’s Consolidated Statement of Operations.
Revenues and Production Taxes Payable
The Company calculates and pays taxes and royalties on oil and natural gas in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements.
Concentrations of Market and Credit Risk
The future results of the Company’s oil and natural gas operations will be affected by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. The current global oversupply of crude oil has caused a sharp decline in oil prices since mid-2014, and an extended period of low prices for oil could have a material adverse effect on the Company’s financial position, cash flows and results of operations.
The Company operates in the exploration, development and production sector of the oil and gas industry. The Company’s receivables include amounts due from purchasers of its oil and natural gas production and amounts due from joint interest partners for their respective portions of operating expenses and exploration and development costs. While certain of these customers and joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the oil or natural gas industry, including the current period of low commodity prices, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. In addition, a portion of the Company’s trade receivables are collateralized.
The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.
Risk Management
The Company utilizes derivative financial instruments to manage risks related to changes in oil and natural gas prices. As of
December 31, 2016
, the Company utilized swaps and two-way and three-way costless collar options to reduce the volatility of oil and natural gas prices on a significant portion of its future expected oil and natural gas production (see Note 4 — Derivative Instruments).
The Company records all derivative instruments on the Consolidated Balance Sheet as either assets or liabilities measured at their estimated fair value. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported in the other income (expense) section of the Company’s Consolidated Statement of Operations. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows.
Derivative financial instruments that hedge the price of oil and natural gas are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. The Company has derivatives in place with
nine
counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has
no
past-due receivables from its counterparties. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.
The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Company’s revolving credit facility (see Note 8— Long-Term Debt). As of
December 31, 2016
, the Company had limitations under its revolving credit facility, including a provision limiting the total amount of production that may be hedged by the Company to the lesser of projected production or
110%
of Current Production (as defined in the revolving credit facility) for the period from 1 to 12 months,
100%
of Current Production for the period from 13 to 24 months,
75%
of Current Production for the period from 25 to 36 months, and
50%
of Current Production for the period from 37 to 60 months after the date of each derivative. As of
December 31, 2016
, the Company was in compliance with these limitations.
Environmental Costs
Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.
Stock-Based Compensation
Restricted Stock Awards
The Company has granted restricted stock awards to employees and directors under its Amended and Restated 2010 Long Term Incentive Plan, the majority of which vest over a
three
-year period. The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. The Company assumed annual forfeiture rates by employee group ranging from
0%
to
20%
based on the Company’s forfeiture history for this type of award. Stock-based compensation expense recorded for restricted stock awards is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.
Performance Share Units
The Company recognizes compensation expense for its performance share units (“PSUs”) granted to its officers under its Amended and Restated 2010 Long Term Incentive Plan. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the performance period, which is generally the vesting period. The fair value of the PSUs is based on the calculation derived from a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probable assessment (see Note 11 — Stock-Based Compensation for a description of the inputs used in this model). The Company assumed annual forfeiture rates by employee group ranging from
3.3%
to
4.6%
based on the Company’s forfeiture history for the employee groups receiving PSUs. Stock-based compensation expense recorded for PSUs is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.
Associated Excess Tax Benefits
Any excess tax benefit arising from the Company’s stock-based compensation plan is recognized as a credit to additional paid-in-capital when realized and is calculated as the amount by which the tax benefit related to the tax deduction received exceeds the deferred tax asset associated with the recorded stock-based compensation expense. As of
December 31, 2016
, the excess federal tax deduction related to stock-based compensation was
$10.6 million
and the excess state tax deduction related to stock-based compensation was
$8.6 million
. Since the Company has been in and continues to be in a net operating loss position for tax purposes, none of the excess tax deduction is reflected in additional paid-in-capital. Pursuant to GAAP, the Company’s deferred tax asset related to net operating loss carryforward is net of the unrealized tax benefit from stock-based compensation.
Treasury Stock
Treasury stock shares represent shares withheld by the Company equivalent to the payroll tax withholding obligations due from employees upon the vesting of restricted stock awards. The Company includes the withheld shares as treasury stock on its Consolidated Balance Sheet and separately pays the payroll tax obligation. These retained shares are not part of a publicly announced program to repurchase shares of the Company’s common stock and are accounted for at cost. The Company does not have a publicly announced program to repurchase shares of its common stock.
Income Taxes
The Company’s provision for taxes includes both federal and state taxes. The Company records its federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax
determination is uncertain. The actual outcome of these future tax consequences could differ significantly from the Company’s estimates, which could impact its financial position, results of operations and cash flows.
The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company did not have any uncertain tax positions outstanding and, as such, did not record a liability for the years ended
December 31, 2016
and
2015
. All deferred tax assets and liabilities, along with any related valuation allowance, are classified as noncurrent on the Company’s Consolidated Balance Sheet.
Recent Accounting Pronouncements
Revenue Recognition
In May 2014, the FASB issued Accounting Standards Update No. 2014-09,
Revenue from Contracts with Customers
(“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14,
Deferral of the Effective Date
(“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
Inventory
In July 2015, the FASB issued Accounting Standards Update No. 2015-11,
Simplifying the Measurement of Inventory
(“ASU 2015-11”). ASU 2015-11 changes the inventory measurement principle from lower of cost or market to lower of cost and net realizable value for entities using the first-in, first out (FIFO) or average cost methods. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. The Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations.
Financial Instruments
In January 2016, the FASB issued Accounting Standards Update No. 2016-01,
Recognition and Measurement of Financial Assets and Financial Liabilities
(“ASU 2016-01”), which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
Leases
In February 2016, the FASB issued Accounting Standards Update No. 2016-02,
Leases
(“ASU 2016-02”), which requires a lessee to recognize lease payment obligations and a corresponding right-of-use asset to be measured at fair value on the balance sheet. ASU 2016-02 also requires certain qualitative and quantitative disclosures about the amount, timing and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
Embedded Derivatives
In March 2016, the FASB issued Accounting Standards Update No. 2016-06,
Contingent Put and Call Options in Debt Instruments
(“ASU 2016-06”), which clarifies what steps are required when assessing whether the economic characteristics and risks of call (put) options are clearly and closely related to the economic characteristics and risks of their debt hosts, which is one of the criteria for bifurcating an embedded derivative. ASU 2016-06 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. The Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations.
Stock-Based Compensation
In March 2016, the FASB issued Accounting Standards Update No. 2016-09,
Improvements to Employee Share-Based Payment Accounting
(“ASU 2016-09”), which updates several aspects of the accounting for share-based payment transactions, including recognition of excess tax benefits and deficiencies, the classification of those excess tax benefits on the statement of cash flows, an accounting policy election for forfeitures, the amount an employer can withhold to cover income taxes and still qualify for equity classification and the classification of those taxes paid on the statement of cash flows. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. The Company will elect to remove forfeiture rates and record a cumulative-effect adjustment to equity at the beginning of 2017 when the guidance is adopted and does not expect the adoption of this guidance to have a material impact on its cash flows or results of operations.
Statement of Cash Flows
In August 2016, the FASB issued Accounting Standards Update No. 2016-15,
Statement of Cash Flows
(“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its statement of cash flows.
Business Combinations
In January 2017, the FASB issued Accounting Standards Update No. 2017-01,
Clarifying the Definition of a Business
(“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
3. Fair Value Measurements
In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as ARO (see Note 9 — Asset Retirement Obligations) and proved oil and natural gas properties upon impairment (see Note 5 — Property, Plant and Equipment), at fair value on a non-recurring basis.
As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.
The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:
Level 1
— Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2
— Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3
— Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.
Financial Assets and Liabilities
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value at December 31, 2016
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
(In thousands)
|
Assets:
|
|
|
|
|
|
|
|
Money market funds
|
$
|
141
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
141
|
|
Commodity derivative instruments (see Note 4)
|
—
|
|
|
362
|
|
|
—
|
|
|
362
|
|
Total assets
|
$
|
141
|
|
|
$
|
362
|
|
|
$
|
—
|
|
|
$
|
503
|
|
Liabilities:
|
|
|
|
|
|
|
|
Commodity derivative instruments (see Note 4)
|
—
|
|
|
72,183
|
|
|
—
|
|
|
72,183
|
|
Total liabilities
|
$
|
—
|
|
|
$
|
72,183
|
|
|
$
|
—
|
|
|
$
|
72,183
|
|
|
|
|
|
|
|
|
|
|
Fair value at December 31, 2015
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
(In thousands)
|
Assets:
|
|
|
|
|
|
|
|
Money market funds
|
$
|
742
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
742
|
|
Commodity derivative instruments (see Note 4)
|
—
|
|
|
155,473
|
|
|
—
|
|
|
155,473
|
|
Total assets
|
$
|
742
|
|
|
$
|
155,473
|
|
|
$
|
—
|
|
|
$
|
156,215
|
|
The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s Consolidated Balance Sheet at
December 31, 2016
and
2015
. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identifies the money market funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained, and there are active markets for the underlying investments.
The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include oil and natural gas swaps and collars. The fair values of the Company’s commodity derivative instruments are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts as there is an active market for these contracts. The third-party preparer performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options. The significant inputs used are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. However, the Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or third-party preparer. The Company compares the third-party preparer’s valuation to counterparty valuation statements, investigating any significant differences, and analyzes monthly valuation changes in relation to movements in crude oil and natural gas forward price curves. The determination of the fair value for derivative instruments also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in an asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the Company’s market credit spread. Based on these calculations, the Company recorded an adjustment to reduce the fair value of its net derivative liability by
$2.0 million
at
December 31, 2016
and an adjustment to reduce the fair value of its net derivative asset by
$0.3 million
at
December 31, 2015
.
There were no transfers between fair value levels during the years ended
December 31, 2016
and
2015
.
4. Derivative Instruments
The Company utilizes derivative financial instruments to manage risks related to changes in crude oil and natural gas prices. The Company’s crude oil and natural gas contracts will settle monthly based on the average NYMEX West Texas Intermediate crude oil index price (“WTI”) and the average NYMEX Henry Hub natural gas index price (“Henry Hub”), respectively. At
December 31, 2016
, the Company utilized swaps and two-way and three-way costless collar options to reduce the volatility of oil and natural gas prices on a significant portion of its future expected oil and natural gas production. A swap
is a sold call and a purchased put established at the same price (both ceiling and floor), which the Company will receive for the volumes under contract. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract.
All derivative instruments are recorded on the Company’s Consolidated Balance Sheet as either assets or liabilities measured at their fair value (see Note 3 – Fair Value Measurements). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value are recognized in the other income (expense) section of the Company’s Consolidated Statement of Operations as a net gain or loss on derivative instruments. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making a payment to or receiving a payment from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows.
At
December 31, 2016
, the Company had the following outstanding commodity derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
Settlement
Period
|
|
Derivative
Instrument
|
|
Volumes
|
|
Weighted Average Prices
|
|
Fair Value
Asset
(Liability)
|
|
|
|
|
Swap
|
|
Sub-Floor
|
|
Floor
|
|
Ceiling
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
Crude oil
|
|
2017
|
|
Swaps
|
|
7,369,000
|
|
Bbl
|
|
$
|
49.48
|
|
|
|
|
|
|
|
|
|
|
$
|
(44,830
|
)
|
Crude oil
|
|
2017
|
|
Two-way collar
|
|
2,672,000
|
|
Bbl
|
|
|
|
|
|
$
|
46.25
|
|
|
$
|
54.37
|
|
|
(10,674
|
)
|
Crude oil
|
|
2017
|
|
Three-way collar
|
|
2,004,000
|
|
Bbl
|
|
|
|
$
|
31.67
|
|
|
$
|
45.83
|
|
|
$
|
59.94
|
|
|
(3,077
|
)
|
Crude oil
|
|
2018
|
|
Swaps
|
|
2,440,000
|
|
Bbl
|
|
$
|
52.93
|
|
|
|
|
|
|
|
|
(8,475
|
)
|
Crude oil
|
|
2018
|
|
Two-way collar
|
|
582,000
|
|
Bbl
|
|
|
|
|
|
$
|
48.40
|
|
|
$
|
55.13
|
|
|
(2,101
|
)
|
Crude oil
|
|
2018
|
|
Three-way collar
|
|
186,000
|
|
Bbl
|
|
|
|
$
|
31.67
|
|
|
$
|
45.83
|
|
|
$
|
59.94
|
|
|
(446
|
)
|
Crude oil
|
|
2019
|
|
Swaps
|
|
155,000
|
|
Bbl
|
|
$
|
53.88
|
|
|
|
|
|
|
|
|
(332
|
)
|
Crude oil
|
|
2019
|
|
Two-way collar
|
|
31,000
|
|
Bbl
|
|
|
|
|
|
$
|
50.00
|
|
|
$
|
55.70
|
|
|
(86
|
)
|
Natural gas
|
|
2017
|
|
Swaps
|
|
5,475,000
|
|
MMBtu
|
|
$
|
3.32
|
|
|
|
|
|
|
|
|
(1,697
|
)
|
Natural gas
|
|
2018
|
|
Swaps
|
|
730,000
|
|
MMBtu
|
|
$
|
2.99
|
|
|
|
|
|
|
|
|
(103
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(71,821
|
)
|
The following table summarizes the location and amounts of gains and losses from the Company’s commodity derivative instruments recorded in the Company’s Consolidated Statement of Operations for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
Statement of Operations Location
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In thousands)
|
Net gain (loss) on derivative instruments
|
|
$
|
(105,317
|
)
|
|
$
|
210,376
|
|
|
$
|
327,011
|
|
In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Consolidated Balance Sheet.
The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Consolidated Balance Sheet:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
Commodity
|
|
Balance Sheet Location
|
|
Gross Recognized Asset/Liabilities
|
|
Gross Amount Offset
|
|
Net Recognized Fair Value Asset/Liability
|
|
|
|
|
(In thousands)
|
Derivative assets:
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
Derivative instruments — current assets
|
|
$
|
482
|
|
|
$
|
(120
|
)
|
|
$
|
362
|
|
Total derivatives assets
|
|
|
|
$
|
482
|
|
|
$
|
(120
|
)
|
|
$
|
362
|
|
Derivative liabilities:
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
Derivative instruments — current liabilities
|
|
$
|
66,838
|
|
|
$
|
(6,369
|
)
|
|
$
|
60,469
|
|
Commodity contracts
|
|
Derivative instruments — non-current liabilities
|
|
14,164
|
|
|
(2,450
|
)
|
|
11,714
|
|
Total derivatives liabilities
|
|
$
|
81,002
|
|
|
$
|
(8,819
|
)
|
|
$
|
72,183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
Commodity
|
|
Balance Sheet Location
|
|
Gross Recognized Asset/Liabilities
|
|
Gross Amount Offset
|
|
Net Recognized Fair Value Asset/Liability
|
|
|
|
|
(In thousands)
|
Derivative assets:
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
Derivative instruments — current assets
|
|
$
|
139,697
|
|
|
$
|
—
|
|
|
$
|
139,697
|
|
Commodity contracts
|
|
Derivative instruments — non-current assets
|
|
15,776
|
|
|
—
|
|
|
15,776
|
|
Total derivatives assets
|
|
|
|
$
|
155,473
|
|
|
$
|
—
|
|
|
$
|
155,473
|
|
5. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment:
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
(In thousands)
|
Proved oil and gas properties
(1)
|
$
|
6,476,833
|
|
|
$
|
5,655,759
|
|
Less: Accumulated depreciation, depletion, amortization and impairment
|
(1,886,732
|
)
|
|
(1,428,427
|
)
|
Proved oil and gas properties, net
|
4,590,101
|
|
|
4,227,332
|
|
Unproved oil and gas properties
|
819,735
|
|
|
628,642
|
|
Other property and equipment
|
618,790
|
|
|
443,265
|
|
Less: Accumulated depreciation
|
(109,059
|
)
|
|
(80,997
|
)
|
Other property and equipment, net
|
509,731
|
|
|
362,268
|
|
Total property, plant and equipment, net
|
$
|
5,919,567
|
|
|
$
|
5,218,242
|
|
__________________
|
|
(1)
|
Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of
$42.9 million
and
$30.7 million
at
December 31, 2016
and
2015
, respectively.
|
Impairment.
The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its proved oil and natural gas properties and then compares such amount to the carrying amount of the proved oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the proved oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current
market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs, as further discussed under Note 3 — Fair Value Measurements.
As of
December 31, 2016
, the Company sold certain proved oil and natural gas properties and other midstream properties (see Note 6 – Acquisitions and Divestiture). For the year ended
December 31, 2016
, the Company recorded an impairment charge of
$3.6 million
, of which
$2.4 million
was included in its midstream services segment and
$1.1 million
was included in its exploration and production segment, to adjust the carrying amount of these assets, net of the associated ARO liabilities, to their estimated fair value. For the year ended
December 31, 2015
, the Company had certain proved oil and natural gas properties held for sale (see Note 6 – Acquisitions and Divestitures). The Company recorded an impairment loss of
$9.4 million
, which was included in earnings in its exploration and production segment for the year ended
December 31, 2015
, to adjust the carrying amount of these assets, net of the associated ARO liabilities, of
$25.9 million
to their estimated fair value of
$16.5 million
. The fair value was determined based on the expected sales price, less costs to sell.
Due to lower expected commodity prices, the Company determined that the carrying amount exceeded expected undiscounted cash flows for certain legacy wells that were producing from conventional reservoirs such as the Madison, Red River and other formations in the Williston Basin other than the Bakken or Three Forks formations for the year ended December 31, 2014. As a result, these assets, with a carrying amount of
$76.4 million
, were written down to their fair value of
$36.4 million
, resulting in an impairment charge of
$40.0 million
, which was included in earnings in the Company’s exploration and production segment for the year ended December 31, 2014. The fair value of these assets was measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs used to determine the fair value included estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, and (iv) a weighted average cost of capital rate based on the assumptions of a market participant. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. For the year ended December 31, 2014, the underlying commodity prices embedded in the Company’s estimated cash flows were determined using NYMEX forward swap prices for
five
years, holding the fifth year price constant thereafter. As of December 31, 2015, a
3%
inflation factor was applied to the underlying commodity prices and future operating and development costs after five years in the Company’s estimated cash flows.
In addition, as a result of expiring leases and periodic assessments of unproved properties, the Company recorded non-cash impairment charges on its unproved oil and gas properties of
$1.1 million
,
$36.6 million
, and
$7.3 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
6. Acquisitions and Divestitures
Williston Basin Acquisition.
On December 1, 2016, the Company completed a purchase and sale agreement with SM Energy Company (“SM Energy”), pursuant to which the Company agreed to purchase approximately
55,000
net acres in the Williston Basin for aggregate consideration of
$765.8 million
in cash, subject to further customary post-closing purchase price adjustments (the “Williston Basin Acquisition”). The Company funded the Williston Basin Acquisition with proceeds from the Company’s October 2016 issuance of its common shares and borrowings under its revolving credit facility.
The Williston Basin Acquisition qualified as a business combination, and as such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the December 1, 2016 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 3 — Fair Value Measurements. The Company recorded the assets acquired and liabilities assumed in the Williston Basin Acquisition at their estimated fair value of
$765.8 million
, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. The Williston Basin Acquisition is considered a taxable transaction; therefore, no deferred tax amounts were recognized at the acquisition date as the tax basis of the assets acquired and liabilities assumed were also recorded at fair value.
The following table summarizes the consideration paid, including customary close adjustments, for the Company’s acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date. The purchase price allocation is preliminary and subject to adjustment, as the final closing statement will be completed in the second quarter of 2017.
|
|
|
|
|
|
At December 1, 2016
|
|
(In thousands)
|
Consideration given to SM Energy:
|
|
Cash
|
$
|
765,752
|
|
Recognized amounts of identifiable assets acquired and liabilities assumed:
|
|
Proved developed properties
|
$
|
421,138
|
|
Proved undeveloped properties
|
154,146
|
|
Unproved lease acquisition costs
|
200,244
|
|
Other property and equipment
|
204
|
|
Inventory
|
974
|
|
Asset retirement obligations
|
(10,954
|
)
|
|
$
|
765,752
|
|
The results of operations for the Williston Basin Acquisition have been included in the Company’s consolidated financial statements since the December 1, 2016 closing date, including
$14.6 million
of total revenue and
$5.9 million
of operating income for the year ended December 31, 2016. In addition, the Company included
$0.3 million
of costs related to the Williston Basin Acquisition in general and administrative expenses on its Consolidated Statement of Operations for the year ended December 31, 2016.
Summarized below are the consolidated results of operations for the year ended December 31, 2016, on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2015. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the Williston Basin Acquisition properties, which were derived from the historical accounting records of the SM Energy. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations.
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
(In thousands)
|
|
Unaudited
|
Revenues
|
$
|
844,148
|
|
|
$
|
991,722
|
|
Net income
|
(210,575
|
)
|
|
265
|
|
Acquisitions.
The Company actively reviews acquisition opportunities on an ongoing basis and acquires additional acreage and producing assets in the Williston Basin to supplement our existing operations. In addition to the Williston Basin Acquisition, the Company spent
$15.8 million
,
$28.8 million
and
$46.2 million
to purchase certain acreage and producing assets through multiple transactions during the years ended December 31,
2016
,
2015
and
2014
, respectively.
2016 Divestiture.
On April 1, 2016, the Company completed the sale of certain legacy wells that have been producing from conventional reservoirs such as the Madison, Red River and other formations in the Williston Basin other than the Bakken or Three Forks formations for cash proceeds of
$12.3 million
, which includes customary post close adjustments, and a
$4.0 million
10%
secured promissory note due in March 2017 (the “2016 Divestiture”). The 2016 Divestiture primarily consisted of oil and gas properties in the Company’s exploration and production segment and included certain other property and equipment in the Company’s midstream segment.
For the years ended
December 31, 2016
and 2015, the Company recorded impairment charges of
$3.6 million
and
$9.4 million
, respectively, which were included in impairment on the Company’s Consolidated Statement of Operations, to adjust the carrying amount of these assets to their estimated fair value, determined based on the expected sales price, less costs to sell.
Net assets held for sale represent the assets that were expected to be sold, net of liabilities, which were expected to be assumed by the purchaser. As of December 31, 2015, the assets sold in the 2016 Divestiture were classified as held for sale in the Company’s exploration and production segment. The Company did not have assets classified as held for sale as of December 31, 2016. The following table presents balance sheet data related to the assets held for sale as of December 31, 2015:
|
|
|
|
|
|
December 31, 2015
|
|
(In thousands)
|
Assets:
|
|
Oil and gas properties
|
$
|
120,926
|
|
Less: accumulated depreciation, depletion, amortization and impairment
|
(94,198
|
)
|
Total assets
|
$
|
26,728
|
|
Liabilities:
|
|
Asset retirement obligation
|
$
|
(10,228
|
)
|
Total liabilities
|
$
|
(10,228
|
)
|
Net assets
|
$
|
16,500
|
|
2014 Divestiture.
On March 5, 2014, the Company completed the sale of certain non-operated properties in and around its Sanish position for cash proceeds of
$324.9 million
, which includes customary post close adjustments. The Company recognized a
$187.0 million
gain on sale of properties in its Consolidated Statement of Operations for the year ended December 31, 2014. The transaction was structured as an Internal Revenue Code Section 1031 like-kind exchange for tax purposes, and as such did not give rise to any current taxable gain.
7. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
(In thousands)
|
Accounts receivable, net
|
|
|
|
Trade accounts
|
$
|
137,065
|
|
|
$
|
96,495
|
|
Joint interest accounts
|
40,322
|
|
|
64,344
|
|
Other accounts
|
28,257
|
|
|
36,570
|
|
Total
|
205,644
|
|
|
197,409
|
|
Allowance for doubtful accounts
|
(1,309
|
)
|
|
—
|
|
Total accounts receivable, net
|
$
|
204,335
|
|
|
$
|
197,409
|
|
|
|
|
|
Inventories
|
|
|
|
Crude oil inventory
|
$
|
7,086
|
|
|
$
|
6,152
|
|
Equipment and materials
|
3,562
|
|
|
4,920
|
|
Total inventory
|
$
|
10,648
|
|
|
$
|
11,072
|
|
|
|
|
|
Accrued liabilities
|
|
|
|
Accrued capital costs
|
$
|
69,311
|
|
|
$
|
110,313
|
|
Accrued lease operating expenses
|
22,221
|
|
|
18,448
|
|
Accrued general and administrative expenses
|
19,061
|
|
|
18,404
|
|
Accrued midstream and well services operating expenses
|
2,365
|
|
|
13,517
|
|
Other accrued liabilities
|
6,215
|
|
|
6,987
|
|
Total accrued liabilities
|
$
|
119,173
|
|
|
$
|
167,669
|
|
|
|
|
|
Revenues and production payable
|
|
|
|
Revenue suspense
|
$
|
55,484
|
|
|
$
|
65,828
|
|
Royalties payable
|
73,033
|
|
|
52,715
|
|
Production taxes payable
|
11,220
|
|
|
13,813
|
|
Total revenue and production payables
|
$
|
139,737
|
|
|
$
|
132,356
|
|
8. Long-Term Debt
The Company’s long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
(In thousands)
|
Senior secured revolving line of credit
|
$
|
363,000
|
|
|
$
|
138,000
|
|
Senior unsecured notes
|
|
|
|
7.25% senior unsecured notes due February 1, 2019
|
54,275
|
|
|
400,000
|
|
6.5% senior unsecured notes due November 1, 2021
|
395,501
|
|
|
400,000
|
|
6.875% senior unsecured notes due March 15, 2022
|
937,080
|
|
|
1,000,000
|
|
6.875% senior unsecured notes due January 15, 2023
|
366,094
|
|
|
400,000
|
|
2.625% senior unsecured convertible notes due September 15, 2023
|
300,000
|
|
|
—
|
|
Total principal of senior unsecured notes
|
2,052,950
|
|
|
2,200,000
|
|
Less: unamortized deferred financing costs on senior unsecured notes
|
(28,268
|
)
|
|
(35,416
|
)
|
Less: unamortized debt discount on senior unsecured convertible notes
|
(90,468
|
)
|
|
—
|
|
Total long-term debt
|
$
|
2,297,214
|
|
|
$
|
2,302,584
|
|
The carrying amount of the Company’s long-term debt reported in the Consolidated Balance Sheet at
December 31, 2016
is
$2,297.2 million
, which includes
$2,053.0 million
of senior unsecured notes, reductions for the unamortized debt discount related to the equity component of the senior unsecured convertible notes and the unamortized deferred financing costs on the senior unsecured notes of
$90.5 million
and
$28.3 million
, respectively, and
$363.0 million
of borrowings under the Company’s revolving credit facility. The Company’s revolving credit facility is recorded at a value that approximates its fair value since its variable interest rate is tied to current market rates. The fair value of the Company’s senior unsecured notes, which are publicly traded and therefore categorized as Level 1 liabilities, is
$2,209.9 million
at
December 31, 2016
.
The Company has
$54.3 million
and
$395.5 million
of Notes maturing in 2019 and 2021, respectively, and indebtedness under its revolving credit facility that becomes due in 2020. The Company does not have any other debt that matures within the five years ending December 31, 2022.
Senior secured revolving line of credit.
The Company has a senior secured revolving line of credit (the “Credit Facility”) of
$2,500.0 million
as of December 31,
2016
, which has a maturity date of April 13, 2020, provided that the
7.25%
senior unsecured notes due February 1, 2019 (the “2019 Notes”), of which
$54.3 million
is outstanding, are retired or refinanced
90
days prior to their maturity. The Credit Facility is restricted to the borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year. On February 23, 2016, the lenders under the Credit Facility (the “Lenders”) completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2016, resulting in a decrease in the borrowing base and aggregate elected commitment from
$1,525.0 million
to
$1,150.0 million
.
Borrowings under the Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including mortgage liens on oil and natural gas properties having at least
90%
(as of
December 31, 2016
) of the reserve value as determined by reserve reports.
Borrowings under the Credit Facility are subject to varying rates of interest based on (1) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a London interbank offered rate (“LIBOR”) loan or a domestic bank prime interest rate loan (defined in the Credit Facility as an Alternate Based Rate or “ABR” loan). As of
December 31, 2016
, any outstanding LIBOR and ABR loans would have borne their respective interest rates plus the applicable margin indicated in the following table:
|
|
|
|
|
|
|
Ratio of Total Outstanding Borrowings to Borrowing Base
|
Applicable Margin
for LIBOR Loans
|
|
Applicable Margin
for ABR Loans
|
Less than .25 to 1
|
1.50
|
%
|
|
0.00
|
%
|
Greater than or equal to .25 to 1 but less than .50 to 1
|
1.75
|
%
|
|
0.25
|
%
|
Greater than or equal to .50 to 1 but less than .75 to 1
|
2.00
|
%
|
|
0.50
|
%
|
Greater than or equal to .75 to 1 but less than .90 to 1
|
2.25
|
%
|
|
0.75
|
%
|
Greater than or equal to .90 to 1
|
2.50
|
%
|
|
1.00
|
%
|
An ABR loan may be repaid at any time before the scheduled maturity of the Credit Facility upon the Company providing advance notification to the Lenders. Interest is paid quarterly on ABR loans based on the number of days an ABR loan is outstanding as of the last business day in March, June, September and December. The Company has the option to convert an ABR loan to a LIBOR-based loan upon providing advance notification to the Lenders. The minimum available loan term is
one month
and the maximum available loan term is
six months
for LIBOR-based loans. Interest for LIBOR loans is paid upon maturity of the loan term. Interim interest is paid every three months for LIBOR loans that have loan terms greater than three months. At the end of a LIBOR loan term, the Credit Facility allows the Company to elect to repay the borrowing, continue a LIBOR loan with the same or differing loan term or convert the borrowing to an ABR loan.
On a quarterly basis, the Company also pays a
0.375%
(as of
December 31, 2016
) annualized commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.
As of
December 31, 2016
, the Credit Facility contained covenants that included, among others:
|
|
•
|
a prohibition against incurring debt, subject to permitted exceptions;
|
|
|
•
|
a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;
|
|
|
•
|
a prohibition against making investments, loans and advances, subject to permitted exceptions;
|
|
|
•
|
restrictions on creating liens and leases on the assets of the Company and its subsidiaries, subject to permitted exceptions;
|
|
|
•
|
restrictions on merging and selling assets outside the ordinary course of business;
|
|
|
•
|
restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;
|
|
|
•
|
a provision limiting oil and natural gas derivative financial instruments;
|
|
|
•
|
a requirement that the Company maintain a ratio of consolidated EBITDAX (as defined in the Credit Facility) to consolidated Interest Expense (as defined in the Credit Facility) of no less than
2.5
to 1.0 for the four quarters ended on the last day of each quarter; and
|
|
|
•
|
a requirement that the Company maintain a Current Ratio (as defined in the Credit Facility) of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the Credit Facility) to consolidated current liabilities (with exclusions as described in the Credit Facility) of no less than
1.0
to 1.0 as of the last day of any fiscal quarter.
|
The Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.
As of
December 31, 2016
, the Company had
$363.0 million
of borrowings and
$12.3 million
of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing base capacity of
$774.7 million
. As of
December 31, 2016
and
2015
, the weighted average interest rate on borrowings under the Credit Facility was
2.5%
and
1.9%
, respectively. The Company was in compliance with the financial covenants of the Credit Facility as of
December 31, 2016
.
Senior unsecured notes.
At
December 31, 2016
, the Company had
$1,753.0 million
principal amount of senior unsecured notes outstanding with maturities ranging from February 2019 to January 2023 and coupons ranging from
6.50%
to
7.25%
(the “Senior Notes”). Prior to certain dates, the Company has the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The 2019 Notes are currently redeemable for cash at a redemption price equal to par. The Company estimates that the fair value of these redemption options is immaterial at
December 31, 2016
and
2015
.
The indentures governing the Senior Notes restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Company’s Senior Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and the Company will cease to be subject to such covenants.
Repurchases of senior unsecured notes.
On September 28, 2016, the Company completed its tender offers to repurchase certain outstanding Senior Notes (the “Tender Offers”). As a result of the Tender Offers, the Company repurchased an aggregate principal amount of
$362.4 million
of its outstanding Senior Notes, consisting of
$344.7 million
principal amount of its 2019 Notes,
$2.2 million
principal amount of its
6.5%
senior unsecured notes due November 2021 (the “2021 Notes”),
$3.4 million
principal amount of its
6.875%
senior unsecured notes due March 2022 (the “2022 Notes”) and
$12.1 million
principal amount of its
6.875%
senior unsecured notes due January 2023 (the “2023 Notes”), for an aggregate cost of
$371.4 million
, including accrued interest and fees for the year ended
December 31, 2016
.
In addition to the Tender Offers, the Company repurchased an aggregate principal amount of
$84.6 million
of its outstanding Senior Notes, consisting of
$1.0 million
principal amount of its 2019 Notes,
$2.3 million
principal amount of its 2021 Notes,
$59.5 million
principal amount of its 2022 Notes and
$21.8 million
principal amount of its 2023 Notes, for an aggregate cost of
$64.5 million
, including accrued interest and fees, for the year ended
December 31, 2016
.
For the year ended
December 31, 2016
, the Company recognized a pre-tax gain of
$4.7 million
related to these repurchases, including the Tender Offers, which were net of unamortized deferred financing costs write-offs of
$6.4 million
, and are reflected in gain on extinguishment of debt in the Company’s Consolidated Statement of Operations.
Senior unsecured convertible notes.
In September 2016, the Company issued
$300.0 million
of
2.625%
senior unsecured convertible notes due September 2023 (the “Senior Convertible Notes”), which resulted in aggregate net proceeds to the Company of
$291.9 million
, after deducting underwriting discounts and commissions and estimated offering expenses. The Company used the proceeds from the Senior Convertible Notes to fund the repurchase of certain outstanding Senior Notes through the Tender Offers. The Senior Convertible Notes will mature on September 15, 2023 unless earlier converted in accordance with their terms.
The Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending on September 30, 2016 (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least
20
trading days (whether or not consecutive) during the period of
30
consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to
130%
of the conversion price on each applicable trading day; (ii) during the
five
business day period after any
five
consecutive trading day period (the “Measurement Period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the Measurement Period is less than
98%
of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events, including certain distributions or a fundamental change. On or after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding their September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of
76.3650
shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equivalent to an initial conversion price of approximately
$13.10
. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, the Company will increase the conversion rate for a holder who elects to convert its Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of
December 31, 2016
, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met.
Upon issuance, the Company separately accounted for the liability and equity components of the Senior Convertible Notes in accordance with Accounting Standards Codification 470-20. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the principal amount of the Senior Convertible Notes and the estimated fair value of the liability component was recorded as a debt discount and will be amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of
8.97%
per annum. The fair value of the Senior Convertible Notes as of the issuance date was estimated at
$206.8 million
, resulting in a debt discount at inception of
$93.2 million
. The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the Senior Convertible
Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital and will not be remeasured as long as it continues to meet the conditions for equity classification.
Transaction costs related to the Senior Convertible Notes issuance were allocated to the liability and equity components based on their relative fair values. Issuance costs attributable to the liability component of
$5.4 million
were recorded in deferred financing costs within long-term debt on the Company’s Consolidated Balance Sheet and are being amortized to interest expense over the term of the Senior Convertible Notes using the effective interest method. Issuance costs attributable to the equity component of
$2.4 million
were recorded as a charge to additional paid-in capital on the Company’s Consolidated Balance Sheet.
Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by the Company, along with its material subsidiaries (the “Guarantors”), which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors, subject to certain customary release provisions. The indentures governing the Notes contain customary events of default.
Deferred financing costs.
As of
December 31, 2016
, the Company had
$33.3 million
of deferred financing costs related to the Notes and the Credit Facility. Deferred financing costs of
$28.3 million
related to the Notes are included in long-term debt on the Company’s Consolidated Balance Sheet as of
December 31, 2016
, and are being amortized over the respective terms of the Notes. Deferred financing costs of
$5.1 million
related to the Credit Facility are included in other assets on the Company’s Consolidated Balance Sheet at
December 31, 2016
, and are being amortized over the term of the Credit Facility. Amortization of deferred financing costs recorded for the year ended
December 31, 2016
,
2015
and
2014
was
$9.8 million
,
$7.2 million
and
$6.4 million
, respectively. These costs are included in interest expense on the Company’s Consolidated Statement of Operations. For the years ended
December 31, 2016
and
2015
, the Company’s interest expense also included
$1.8 million
and
$0.5 million
, respectively, for unamortized deferred financing costs related to the Credit Facility, which were written off in proportion to the decreases in the borrowing base.
No
deferred financing costs related to the Credit Facility were written off during the year ended December 31, 2014. Aforementioned, the gain on extinguishment of debt in the Company’s Consolidated Statement of Operations included unamortized deferred financing costs write-offs of
$6.4 million
related to the repurchased Notes for the year ended
December 31, 2016
. No deferred financing costs related to the Notes were written off during the years ended
December 31, 2015
and 2014.
9. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO during the years ended
December 31, 2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
(In thousands)
|
Asset retirement obligation — beginning of period
|
$
|
35,812
|
|
|
$
|
42,549
|
|
Liabilities incurred during period
(1)
|
11,811
|
|
|
1,245
|
|
Liabilities settled during period
(2)
|
(480
|
)
|
|
(218
|
)
|
Accretion expense during period
(1)(3)
|
1,973
|
|
|
2,223
|
|
Revisions to estimates
|
571
|
|
|
241
|
|
Liabilities held for sale
(4)
|
—
|
|
|
(10,228
|
)
|
Asset retirement obligation — end of period
|
$
|
49,687
|
|
|
$
|
35,812
|
|
__________________
|
|
(1)
|
Includes costs for wells acquired in the Williston Basin Acquisition (see Note 6 – Acquisitions and Divestitures) as of December 31, 2016.
|
|
|
(2)
|
Liabilities settled during the year ended
December 31, 2016
included ARO related to the sold properties (see Note 6 – Acquisitions and Divestitures).
|
|
|
(3)
|
Included in depreciation, depletion and amortization on the Company’s Consolidated Statement of Operations.
|
|
|
(4)
|
Represents ARO related to the properties held for sale as of December 31, 2015 (see Note 6 – Acquisitions and Divestitures).
|
At
December 31, 2016
and
2015
, the current portion of the total ARO balance was approximately
$0.7 million
and
$0.5 million
, respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheet.
10. Income Taxes
The Company’s income tax expense (benefit) consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Current:
|
|
|
|
|
|
Federal
|
$
|
—
|
|
|
$
|
(9
|
)
|
|
$
|
134
|
|
State
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
134
|
|
Deferred:
|
|
|
|
|
|
Federal
|
(117,781
|
)
|
|
(11,667
|
)
|
|
273,576
|
|
State
|
(10,757
|
)
|
|
(4,447
|
)
|
|
33,881
|
|
|
(128,538
|
)
|
|
(16,114
|
)
|
|
307,457
|
|
Total income tax expense (benefit)
|
$
|
(128,538
|
)
|
|
$
|
(16,123
|
)
|
|
$
|
307,591
|
|
The reconciliation of income taxes calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate for the years ended
December 31, 2016
,
2015
and
2014
, is set forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(%)
|
|
(In thousands)
|
|
(%)
|
|
(In thousands)
|
|
(%)
|
|
(In thousands)
|
U.S. federal tax statutory rate
|
35.00
|
%
|
|
$
|
(130,044
|
)
|
|
35.00
|
%
|
|
$
|
(19,730
|
)
|
|
35.00
|
%
|
|
$
|
285,064
|
|
State income taxes, net of federal income tax benefit
|
2.27
|
%
|
|
(8,435
|
)
|
|
5.11
|
%
|
|
(2,883
|
)
|
|
2.81
|
%
|
|
22,901
|
|
Non-deductible stock-based compensation (shortfall)
|
(1.83
|
)%
|
|
6,808
|
|
|
(10.17
|
)%
|
|
5,734
|
|
|
—
|
%
|
|
—
|
|
Other
|
(0.85
|
)%
|
|
3,133
|
|
|
(1.34
|
)%
|
|
756
|
|
|
(0.05
|
)%
|
|
(374
|
)
|
Annual effective tax expense (benefit)
|
34.59
|
%
|
|
$
|
(128,538
|
)
|
|
28.60
|
%
|
|
$
|
(16,123
|
)
|
|
37.76
|
%
|
|
$
|
307,591
|
|
The effective tax rate was lower for the years ended December 31, 2016 and 2015 due to the Company’s pre-tax loss and the impact of permanent differences. The permanent differences were primarily amounts expensed for book purposes versus the amounts deductible for income tax purposes related to stock-based compensation vesting during the year ended December 31, 2015 at stock prices lower than the grant date values. The impact of these permanent differences was partially offset by a reduction in the North Dakota statutory tax rate in 2015. For the year ended December 31,
2014
, the Company’s effective tax rate differed from the federal statutory rate of
35%
primarily due to state income taxes.
Significant components of the Company’s deferred tax assets and liabilities as of
December 31, 2016
and
2015
, were as follows:
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
(In thousands)
|
Deferred tax assets
|
|
|
|
Net operating loss carryforward
|
$
|
228,279
|
|
|
$
|
121,248
|
|
Bonus and stock-based compensation
|
9,483
|
|
|
11,222
|
|
Derivative instruments
|
25,738
|
|
|
—
|
|
Other tax attribute carryovers
|
1,712
|
|
|
1,601
|
|
Total deferred tax assets
|
265,212
|
|
|
134,071
|
|
Less valuation allowance
|
(1,344
|
)
|
|
—
|
|
Net deferred tax assets
|
263,868
|
|
|
134,071
|
|
Deferred tax liabilities
|
|
|
|
Oil and natural gas properties
|
744,977
|
|
|
696,498
|
|
Derivative instruments
|
—
|
|
|
45,728
|
|
Other deferred tax liabilities
|
32,420
|
|
|
—
|
|
Total deferred tax liabilities
|
777,397
|
|
|
742,226
|
|
Total net deferred tax liabilities
|
$
|
513,529
|
|
|
$
|
608,155
|
|
The Company generated a federal net operating tax loss of
$411.1 million
for the year ended
December 31, 2016
. The net operating loss carryforwards consist of
$620.7 million
of federal net operating loss carryforwards, which expire between 2030 and 2036, and
$505.1 million
of state net operating loss carryforwards, which expire between 2017 and 2036. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be more likely than not. When the future utilization of some portion of the carryforwards is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded tax benefits from such assets. During the year ended
December 31, 2016
, the Company recorded a valuation allowance of
$0.8 million
and
$0.6 million
for Montana net operating losses and for federal charitable contribution carryovers, respectively, based on management’s assessment that it is more likely than not that these net deferred tax assets will not be realized prior to their expiration due to their short carryover periods, current economic conditions and expectations for the future. Management determined that a valuation allowance was not required for its U.S. federal and North Dakota tax net operating loss carryforwards as they are expected to be fully utilized before their expiration.
Pursuant to authoritative guidance, the Company’s
$228.3 million
deferred tax asset related to net operating loss carryforwards is net of
$4.0 million
of unrealized excess tax benefits related to excess stock-based compensation on federal and state net operating losses of
$10.6 million
and
$8.6 million
, respectively.
Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of
December 31, 2016
, the Company had
no
unrecognized tax benefits. With respect to income taxes, the Company’s policy is to account for interest charges as interest expense and any penalties as tax expense in its Consolidated Statement of Operations. The Company files income tax returns in the U.S. federal jurisdiction and in North Dakota, Montana and Texas. The statute of limitation for the year ended
December 31, 2016
will expire in 2020. The Company’s earliest open year in its key jurisdictions is 2014 for both the U.S. federal jurisdiction and various U.S. states, however, net operating losses originating in prior years are subject to examination when utilized.
11. Stock-Based Compensation
Restricted stock awards.
The Company has granted restricted stock awards to employees and directors under its Amended and Restated 2010 Long Term Incentive Plan, the majority of which vest over a
three
-year period. The maximum number of shares available for grant under the Amended and Restated 2010 Long Term Incentive Plan is
16,050,000
. The fair value of restricted stock grants is based on the closing sales price of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. The Company assumed annual forfeiture rates by employee group ranging fro
m
0%
to
20%
b
ased on the Company’s forfeiture history for this type of award.
The following table summarizes information related to restricted stock held by the Company’s employees and directors for the periods presented:
|
|
|
|
|
|
|
|
|
Shares
|
|
Weighted Average
Grant Date
Fair Value per Share
|
Non-vested shares outstanding December 31, 2015
|
1,841,149
|
|
|
$
|
24.03
|
|
Granted
|
3,407,900
|
|
|
5.63
|
|
Vested
|
(1,046,521
|
)
|
|
22.31
|
|
Forfeited
|
(221,755
|
)
|
|
10.66
|
|
Non-vested shares outstanding December 31, 2016
|
3,980,773
|
|
|
$
|
9.48
|
|
Stock-based compensation expense recorded for restricted stock awards was
$20.0 million
,
$21.4 million
and
$18.2 million
, respectively, for each of the years ended
December 31, 2016
,
2015
and
2014
, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. The fair value of awards vested was
$6.9 million
,
$9.5 million
and
$18.3 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively. The weighted average grant date fair value of restricted stock awards granted was
$5.63
per share,
$14.28
per share and
$42.55
per share for the years ended
December 31, 2016
,
2015
and
2014
, respectively. Unrecognized expense as of
December 31, 2016
for all outstanding restricted stock awards was
$23.2 million
and will be recognized over a weighted average period of
1.8
years.
Performance share units.
The Company has granted PSUs to officers of the Company under its Amended and Restated 2010 Long Term Incentive Plan. The PSUs are awards of restricted stock units, and each PSU that is earned represents the right to receive
one
share of the Company’s common stock. The Company assumed annual forfeiture rates by employee group ranging from
3.3%
to
4.6%
based on the Company’s forfeiture history for the employee groups receiving PSUs.
The Company accounted for these PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the total shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the performance periods. Depending on the Company’s TSR performance relative to the defined peer group, award recipients will earn between
0%
and
200%
of the initial PSUs granted. The grant date fair value for each grant of PSUs is recognized on a straight-line basis over a four-year total performance period. All compensation expense related to the PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved.
The following table summarizes information related to PSUs held by the Company’s officers for the periods presented:
|
|
|
|
|
|
|
|
|
Units
|
|
Weighted Average
Grant Date
Fair Value per Unit
|
Non-vested PSUs at December 31, 2015
|
664,254
|
|
|
$
|
22.96
|
|
Granted
|
910,000
|
|
|
3.00
|
|
Vested
|
(104,310
|
)
|
|
37.98
|
|
Forfeited
|
(82,325
|
)
|
|
9.83
|
|
Non-vested PSUs at December 31, 2016
|
1,387,619
|
|
|
$
|
9.52
|
|
Stock-based compensation expense recorded for PSUs for the years ended
December 31, 2016
,
2015
and
2014
was
$4.2 million
,
$3.9 million
and
$3.1 million
, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. The fair value of PSUs vested was
$1.0 million
and
$0.8 million
for the years ended
December 31, 2016
and
2015
, respectively.
No
PSUs vested during the year ended December 31, 2014. The weighted average grant date fair value of PSUs granted was
$3.00
per share,
$11.20
per share and
$41.71
per share for the years ended
December 31, 2016
,
2015
and
2014
, respectively. Unrecognized expense as of
December 31, 2016
for all outstanding PSUs was
$6.6 million
and will be recognized over a weighted average period of
2.0
years.
The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model, which results in an expected percentage of PSUs to be earned during the performance period. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, initial value, risk-free interest rate, volatility and correlation coefficients. The risk-free interest rate is the U.S. Treasury bond rate on the date of grant that corresponds to the total performance period. The initial value is the average of the volume weighted average prices
for the
30
trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility is the standard deviation of the average percentage change in stock price over a historical period for the Company and each of its peers. The correlation coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data.
The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the PSUs granted during the periods presented:
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
Forecast period (years)
|
4
|
|
|
4
|
|
|
4
|
|
Risk-free interest rate
|
1.25
|
%
|
|
0.99
|
%
|
|
1.12
|
%
|
Oasis stock price volatility
|
59.38
|
%
|
|
50.11
|
%
|
|
44.49
|
%
|
The Monte Carlo simulation model resulted in an expected percentage of PSUs to be earned of
69%
,
86%
and
98%
for the
2016
,
2015
and
2014
grants, respectively.
Associated tax benefit.
For the years ended December 31,
2016
,
2015
and
2014
, the Company had an associated tax benefit of
$8.3 million
,
$8.7 million
and
$8.4 million
, respectively, related to all stock-based compensation.
12. Common Stock
On
October 21, 2016
, the Company completed a public offering of
55,200,000
shares of its common stock (including
7,200,000
shares issued pursuant to the underwriters’ option to purchase additional common stock) at a purchase price to the public of
$10.80
per share. Net proceeds from the offering were
$583.9 million
, after deducting underwriting discounts and commissions and offering expenses, of which
$0.6 million
is included in common stock and
$583.3 million
is included in additional paid-in capital on the Company’s Consolidated Balance Sheet. The Company used the net proceeds to fund a portion of the Williston Basin Acquisition.
On
February 2, 2016
, the Company completed a public offering of
39,100,000
shares of its common stock (including
5,100,000
shares issued pursuant to the underwriters’ option to purchase additional common stock) at an offering price of
$4.685
per share. Net proceeds from the offering were
$182.8 million
, after deducting underwriting discounts and commissions and offering expenses, of which
$0.4 million
is included in common stock and
$182.4 million
is included in additional paid-in capital on the Company’s Consolidated Balance Sheet. The Company used the net proceeds for general corporate purposes.
On
March 9, 2015
, the Company completed a public offering of
36,800,000
shares of its common stock (including
4,800,000
shares issued pursuant to the underwriters’ option to purchase additional common stock) at an offering price of
$12.80
per share. Net proceeds from the offering were
$462.8 million
, after deducting underwriting discounts and commissions and offering expenses, of which
$0.4 million
is included in common stock and
$462.4 million
is included in additional paid-in capital on the Company’s Consolidated Balance Sheet. The Company used the net proceeds to repay outstanding indebtedness under its Credit Facility and for general corporate purposes.
These offerings were made pursuant to an effective shelf registration statement on Form S-3 filed with the Securities and Exchange Commission (the “SEC”) on July 15, 2014.
13. Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares, PSUs outstanding and contingently issuable shares of convertible debt during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to income (loss) available to common stockholders in the calculation of diluted earnings (loss) per share.
The following is a calculation of the basic and diluted weighted average shares outstanding for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Basic weighted average common shares outstanding
|
183,615
|
|
|
130,186
|
|
|
99,677
|
|
Dilution effect of stock awards at end of period
(1)
|
—
|
|
|
—
|
|
|
688
|
|
Diluted weighted average common shares outstanding
|
183,615
|
|
|
130,186
|
|
|
100,365
|
|
__________________
|
|
(1)
|
No unvested stock awards were included in computing loss per share for the years ended
December 31, 2016
and
2015
because the effect was anti-dilutive.
|
During the years ended
December 31, 2016
and
2015
, the Company incurred a net loss and therefore the diluted loss per share calculation for those periods excludes the anti-dilutive effect of
5,075,301
and
2,842,144
unvested stock awards, respectively. In addition, the diluted earnings per share calculation for the year ended
December 31, 2014
excludes the dilutive effect of
979,795
unvested stock awards that were anti-dilutive under the treasury stock method.
The Company has the option to settle conversions of its Senior Convertible Notes with cash, shares of common stock or a combination of cash and common stock at its election (see Note 8 — Long-Term Debt). The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (conversion spread) is considered in the diluted earnings per share computation under the treasury stock method. As of
December 31, 2016
, the conversion value did not exceed the principal amount of the notes, and accordingly, there was no impact to diluted earnings per share for the year ended
December 31, 2016
.
14. Business Segment Information
The Company’s exploration and production segment is engaged in the acquisition and development of oil and natural gas properties. Revenues for the exploration and production segment are derived from the sale of oil and natural gas production. The Company’s midstream services business segment (OMS) performs salt water gathering and disposal services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other midstream services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the midstream segment are primarily derived from salt water pipeline transport, salt water disposal, fresh water sales, natural gas gathering and processing and crude oil gathering. The Company’s well services business segment (OWS) performs completion services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the well services segment are derived from providing well services, product sales and equipment rentals. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated working interest owners are included in the Company’s Consolidated Statement of Operations. These segments represent the Company’s
three
operating units, each offering different products and services. The Company’s corporate activities have been allocated to the supported business segments accordingly.
Management evaluates the performance of the Company’s business segments based on operating income, which is defined as segment operating revenues less operating expenses, including DD&A. The following table summarizes financial information for the Company’s three business segments for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
Production
|
|
Midstream Services
|
|
Well Services
|
|
Eliminations
|
|
Consolidated
|
|
|
Year Ended December 31, 2016
|
|
Revenues from external customers
|
$
|
635,505
|
|
|
$
|
35,406
|
|
|
$
|
33,754
|
|
|
$
|
—
|
|
|
$
|
704,665
|
|
Inter-segment revenues
|
—
|
|
|
85,447
|
|
|
59,595
|
|
|
(145,042
|
)
|
|
—
|
|
Total revenues
|
635,505
|
|
|
120,853
|
|
|
93,349
|
|
|
(145,042
|
)
|
|
704,665
|
|
Operating income (loss)
|
(196,179
|
)
|
|
68,868
|
|
|
3,428
|
|
|
(6,950
|
)
|
|
(130,833
|
)
|
Other income (expense)
|
(240,290
|
)
|
|
(474
|
)
|
|
43
|
|
|
—
|
|
|
(240,721
|
)
|
Income (loss) before income taxes
|
$
|
(436,469
|
)
|
|
$
|
68,394
|
|
|
$
|
3,471
|
|
|
$
|
(6,950
|
)
|
|
$
|
(371,554
|
)
|
Total assets
(1)
|
$
|
5,868,747
|
|
|
$
|
431,095
|
|
|
$
|
51,167
|
|
|
$
|
(172,377
|
)
|
|
$
|
6,178,632
|
|
Property, plant and equipment, net
|
5,620,558
|
|
|
424,197
|
|
|
47,189
|
|
|
(172,377
|
)
|
|
5,919,567
|
|
Capital expenditures
(2)
|
1,017,411
|
|
|
170,386
|
|
|
680
|
|
|
(6,950
|
)
|
|
1,181,527
|
|
Depreciation, depletion and amortization
|
467,894
|
|
|
8,525
|
|
|
14,892
|
|
|
(14,980
|
)
|
|
476,331
|
|
Impairment
|
2,253
|
|
|
2,431
|
|
|
—
|
|
|
—
|
|
|
4,684
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2015
|
|
Revenues from external customers
|
$
|
721,672
|
|
|
$
|
23,769
|
|
|
$
|
44,294
|
|
|
$
|
—
|
|
|
$
|
789,735
|
|
Inter-segment revenues
|
—
|
|
|
80,926
|
|
|
177,184
|
|
|
(258,110
|
)
|
|
—
|
|
Total revenues
|
721,672
|
|
|
104,695
|
|
|
221,478
|
|
|
(258,110
|
)
|
|
789,735
|
|
Operating income (loss)
|
(177,512
|
)
|
|
60,668
|
|
|
49,145
|
|
|
(46,465
|
)
|
|
(114,164
|
)
|
Other income (expense)
|
58,542
|
|
|
(801
|
)
|
|
52
|
|
|
—
|
|
|
57,793
|
|
Income (loss) before income taxes
|
$
|
(118,970
|
)
|
|
$
|
59,867
|
|
|
$
|
49,197
|
|
|
$
|
(46,465
|
)
|
|
$
|
(56,371
|
)
|
Total assets
(1)(3)
|
$
|
5,478,439
|
|
|
$
|
409,635
|
|
|
$
|
470,614
|
|
|
$
|
(709,313
|
)
|
|
$
|
5,649,375
|
|
Property, plant and equipment, net
|
5,057,311
|
|
|
264,956
|
|
|
61,402
|
|
|
(165,427
|
)
|
|
5,218,242
|
|
Capital expenditures
(2)
|
537,806
|
|
|
96,947
|
|
|
21,711
|
|
|
(46,465
|
)
|
|
609,999
|
|
Depreciation, depletion and amortization
|
479,693
|
|
|
5,764
|
|
|
19,073
|
|
|
(19,208
|
)
|
|
485,322
|
|
Impairment
|
46,109
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46,109
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
Revenues from external customers
|
$
|
1,304,004
|
|
|
$
|
11,614
|
|
|
$
|
74,610
|
|
|
$
|
—
|
|
|
$
|
1,390,228
|
|
Inter-segment revenues
|
—
|
|
|
39,344
|
|
|
192,774
|
|
|
(232,118
|
)
|
|
—
|
|
Total revenues
|
1,304,004
|
|
|
50,958
|
|
|
267,384
|
|
|
(232,118
|
)
|
|
1,390,228
|
|
Operating income
|
610,850
|
|
|
22,730
|
|
|
70,878
|
|
|
(58,806
|
)
|
|
645,652
|
|
Other income (expense)
|
168,741
|
|
|
—
|
|
|
75
|
|
|
—
|
|
|
168,816
|
|
Income before income taxes
|
$
|
779,591
|
|
|
$
|
22,730
|
|
|
$
|
70,953
|
|
|
$
|
(58,806
|
)
|
|
$
|
814,468
|
|
Total assets
(1)
|
$
|
5,772,959
|
|
|
$
|
212,685
|
|
|
$
|
281,844
|
|
|
$
|
(358,412
|
)
|
|
$
|
5,909,076
|
|
Property, plant and equipment, net
|
5,074,588
|
|
|
172,394
|
|
|
58,767
|
|
|
(118,963
|
)
|
|
5,186,786
|
|
Capital expenditures
(2)
|
1,525,168
|
|
|
68,939
|
|
|
37,292
|
|
|
(58,806
|
)
|
|
1,572,593
|
|
Depreciation, depletion and amortization
|
406,960
|
|
|
3,744
|
|
|
14,080
|
|
|
(12,450
|
)
|
|
412,334
|
|
Impairment
|
47,238
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47,238
|
|
__________________
|
|
(1)
|
Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets.
|
|
|
(2)
|
Capital expenditures (including acquisitions) reflected in the table above differ from the amounts for capital expenditures and acquisitions of oil and gas properties shown in the Company’s Consolidated Statement of Cash Flows because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the Consolidated Statement of Cash Flows are presented on a cash
|
basis. Acquisitions totaled
$781.5 million
,
$28.7 million
and
$37.2 million
for the years ended December 31, 2016, 2015 and 2014, respectively, in the exploration and production segment.
|
|
(3)
|
Total assets for the exploration and production segment include
$26.7 million
of assets held for sale as of December 31, 2015.
|
15. Significant Concentrations
Major customers.
For the year ended
December 31, 2016
, sales to PBF Holding Company LLC accounted for approximately
10%
of the Company’s total sales. For the year ended
December 31, 2015
, sales to Shell Trading (US) Company accounted for approximately
10%
of the Company’s total sales. For the year ended December 31,
2014
, sales to Musket Corporation accounted for approximately
13%
of the Company’s total sales.
No
other purchasers accounted for more than 10% of the Company’s total sales for the years ended
December 31, 2016
,
2015
and
2014
. Total sales include revenues from the Company’s exploration and production segment only, as OMS and OWS provide services to OPNA.
Substantially all of the Company’s accounts receivable result from sales of oil and natural gas as well as joint interest billings (“JIB”) to third-party companies who have working interest payment obligations in projects completed by the Company. Exxon Mobil Corporation and XTO Energy, Inc. accounted for approximately
22%
and
17%
, respectively, of the Company’s JIB receivables balance at
December 31, 2016
. Statoil Oil & Gas LP and HRG, Inc. accounted for approximately
17%
and
10%
, respectively, of the Company’s JIB receivables balance at
December 31, 2015
.
This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions, including the current downturn in oil prices. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative oil and natural gas purchasers in the Company’s producing regions.
16. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of
December 31, 2016
. The commitments under these arrangements are not recorded in the accompanying Consolidated Balance Sheet. The amounts disclosed represent undiscounted cash flows on a gross basis, and no inflation elements have been applied.
Lease obligations
. The Company has operating leases for office space and other property and equipment. The Company incurred rental expense of
$6.3 million
,
$7.2 million
and
$5.0 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively, included in general and administrative expenses on its Consolidated Statement of Operations.
Future minimum annual rental commitments under non-cancelable leases at
December 31, 2016
are as follows:
|
|
|
|
|
|
(In thousands)
|
2017
|
$
|
5,530
|
|
2018
|
4,935
|
|
2019
|
4,986
|
|
2020
|
3,735
|
|
|
$
|
19,186
|
|
Volume commitment agreements.
As of
December 31, 2016
, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately
41.1
MMBbl of crude oil,
23.0
MMBbl of natural gas liquids,
211.1
Bcf of natural gas and 31.7 MMBbl of fresh water, prior to any applicable volume credits, within specified timeframes, all of which are
ten
years or less. For the years ended
December 31, 2016
,
2015
and
2014
, the Company incurred transportation and purchase costs of
$16.1 million
,
$7.3 million
and
$5.6 million
related to the these agreements. The future commitments under certain agreements cannot be estimated as they are based on fixed differentials relative to WTI under the agreements as compared to the differential relative to WTI for the Williston Basin for the production month.
The estimable future commitments under these volume commitment agreements as of
December 31, 2016
are as follows:
|
|
|
|
|
|
(In thousands)
|
2017
|
$
|
33,103
|
|
2018
|
57,654
|
|
2019
|
63,505
|
|
2020
|
61,653
|
|
2021
|
62,092
|
|
Thereafter
|
194,229
|
|
|
$
|
472,236
|
|
Litigation.
The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, the Company believes that all such matters are without merit and involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on its financial condition, results of operations or cash flows. When the Company determines that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.
17. Subsequent Events
The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statements.
18. Condensed Consolidating Financial Statements
The Notes (see Note 8 — Long-Term Debt) are guaranteed on a senior unsecured basis by the Guarantors, which are
100%
owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors. Certain of the Company’s immaterial wholly-owned subsidiaries do not guarantee the Notes (“Non-Guarantor Subsidiaries”).
The following financial information reflects consolidating financial information of the parent company, Oasis Petroleum Inc. (“Issuer”), and its Guarantors on a combined basis, prepared on the equity basis of accounting. The Non-Guarantor Subsidiaries are immaterial and, therefore, not presented separately. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantors operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantors because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantors.
Condensed Consolidating Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
Parent/
Issuer
|
|
Combined
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
(In thousands, except share data)
|
ASSETS
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
166
|
|
|
$
|
11,060
|
|
|
$
|
—
|
|
|
$
|
11,226
|
|
Accounts receivables, net
|
—
|
|
|
204,335
|
|
|
—
|
|
|
204,335
|
|
Accounts receivable – affiliates
|
252,000
|
|
|
27,619
|
|
|
(279,619
|
)
|
|
—
|
|
Inventory
|
—
|
|
|
10,648
|
|
|
—
|
|
|
10,648
|
|
Prepaid expenses
|
275
|
|
|
7,348
|
|
|
—
|
|
|
7,623
|
|
Derivative instruments
|
—
|
|
|
362
|
|
|
—
|
|
|
362
|
|
Other current assets
|
—
|
|
|
4,355
|
|
|
—
|
|
|
4,355
|
|
Total current assets
|
252,441
|
|
|
265,727
|
|
|
(279,619
|
)
|
|
238,549
|
|
Property, plant and equipment
|
|
|
|
|
|
|
|
Oil and gas properties (successful efforts method)
|
—
|
|
|
7,296,568
|
|
|
—
|
|
|
7,296,568
|
|
Other property and equipment
|
—
|
|
|
618,790
|
|
|
—
|
|
|
618,790
|
|
Less: accumulated depreciation, depletion, amortization and impairment
|
—
|
|
|
(1,995,791
|
)
|
|
—
|
|
|
(1,995,791
|
)
|
Total property, plant and equipment, net
|
—
|
|
|
5,919,567
|
|
|
—
|
|
|
5,919,567
|
|
Assets held for sale
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Investments in and advances to subsidiaries
|
4,451,192
|
|
|
—
|
|
|
(4,451,192
|
)
|
|
—
|
|
Derivative instruments
|
—
|
|
|
|
|
|
—
|
|
|
—
|
|
Deferred income taxes
|
220,058
|
|
|
—
|
|
|
(220,058
|
)
|
|
—
|
|
Other assets
|
—
|
|
|
20,516
|
|
|
—
|
|
|
20,516
|
|
Total assets
|
$
|
4,923,691
|
|
|
$
|
6,205,810
|
|
|
$
|
(4,950,869
|
)
|
|
$
|
6,178,632
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
Accounts payable
|
$
|
—
|
|
|
$
|
4,645
|
|
|
$
|
—
|
|
|
$
|
4,645
|
|
Accounts payable – affiliates
|
27,619
|
|
|
252,000
|
|
|
(279,619
|
)
|
|
—
|
|
Revenues and production taxes payable
|
—
|
|
|
139,737
|
|
|
—
|
|
|
139,737
|
|
Accrued liabilities
|
12
|
|
|
119,161
|
|
|
—
|
|
|
119,173
|
|
Accrued interest payable
|
38,689
|
|
|
315
|
|
|
—
|
|
|
39,004
|
|
Derivative instruments
|
—
|
|
|
60,469
|
|
|
—
|
|
|
60,469
|
|
Advances from joint interest partners
|
—
|
|
|
7,597
|
|
|
—
|
|
|
7,597
|
|
Other current liabilities
|
—
|
|
|
10,490
|
|
|
—
|
|
|
10,490
|
|
Total current liabilities
|
66,320
|
|
|
594,414
|
|
|
(279,619
|
)
|
|
381,115
|
|
Long-term debt
|
1,934,214
|
|
|
363,000
|
|
|
—
|
|
|
2,297,214
|
|
Deferred income taxes
|
—
|
|
|
733,587
|
|
|
(220,058
|
)
|
|
513,529
|
|
Asset retirement obligations
|
—
|
|
|
48,985
|
|
|
—
|
|
|
48,985
|
|
Derivative instruments
|
—
|
|
|
11,714
|
|
|
—
|
|
|
11,714
|
|
Other liabilities
|
—
|
|
|
2,918
|
|
|
—
|
|
|
2,918
|
|
Total liabilities
|
2,000,534
|
|
|
1,754,618
|
|
|
(499,677
|
)
|
|
3,255,475
|
|
Stockholders’ equity
|
|
|
|
|
|
|
|
Capital contributions from affiliates
|
—
|
|
|
3,388,893
|
|
|
(3,388,893
|
)
|
|
—
|
|
Common stock, $0.01 par value: 450,000,000 shares authorized; 237,201,064 shares issued and 236,344,172 shares outstanding
|
2,331
|
|
|
—
|
|
|
—
|
|
|
2,331
|
|
Treasury stock, at cost: 856,892 shares
|
(15,950
|
)
|
|
—
|
|
|
—
|
|
|
(15,950
|
)
|
Additional paid-in-capital
|
2,345,271
|
|
|
8,743
|
|
|
(8,743
|
)
|
|
2,345,271
|
|
Retained earnings
|
591,505
|
|
|
1,053,556
|
|
|
(1,053,556
|
)
|
|
591,505
|
|
Total stockholders’ equity
|
2,923,157
|
|
|
4,451,192
|
|
|
(4,451,192
|
)
|
|
2,923,157
|
|
Total liabilities and stockholders’ equity
|
$
|
4,923,691
|
|
|
$
|
6,205,810
|
|
|
$
|
(4,950,869
|
)
|
|
$
|
6,178,632
|
|
Condensed Consolidating Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
Parent/
Issuer
|
|
Combined
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
(In thousands, except share data)
|
ASSETS
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
777
|
|
|
$
|
8,953
|
|
|
$
|
—
|
|
|
$
|
9,730
|
|
Accounts receivable, net
|
15
|
|
|
197,394
|
|
|
—
|
|
|
197,409
|
|
Accounts receivable – affiliates
|
1,248
|
|
|
247,488
|
|
|
(248,736
|
)
|
|
—
|
|
Inventory
|
—
|
|
|
11,072
|
|
|
—
|
|
|
11,072
|
|
Prepaid expenses
|
278
|
|
|
7,050
|
|
|
—
|
|
|
7,328
|
|
Derivative instruments
|
—
|
|
|
139,697
|
|
|
—
|
|
|
139,697
|
|
Other current assets
|
—
|
|
|
50
|
|
|
—
|
|
|
50
|
|
Total current assets
|
2,318
|
|
|
611,704
|
|
|
(248,736
|
)
|
|
365,286
|
|
Property, plant and equipment
|
|
|
|
|
|
|
|
Oil and gas properties (successful efforts method)
|
—
|
|
|
6,284,401
|
|
|
—
|
|
|
6,284,401
|
|
Other property and equipment
|
—
|
|
|
443,265
|
|
|
—
|
|
|
443,265
|
|
Less: accumulated depreciation, depletion, amortization and impairment
|
—
|
|
|
(1,509,424
|
)
|
|
—
|
|
|
(1,509,424
|
)
|
Total property, plant and equipment, net
|
—
|
|
|
5,218,242
|
|
|
—
|
|
|
5,218,242
|
|
Assets held for sale
|
—
|
|
|
26,728
|
|
|
—
|
|
|
26,728
|
|
Investments in and advances to subsidiaries
|
4,573,172
|
|
|
—
|
|
|
(4,573,172
|
)
|
|
—
|
|
Derivative instruments
|
—
|
|
|
15,776
|
|
|
—
|
|
|
15,776
|
|
Deferred income taxes
|
205,174
|
|
|
—
|
|
|
(205,174
|
)
|
|
—
|
|
Other assets
|
100
|
|
|
23,243
|
|
|
—
|
|
|
23,343
|
|
Total assets
|
$
|
4,780,764
|
|
|
$
|
5,895,693
|
|
|
$
|
(5,027,082
|
)
|
|
$
|
5,649,375
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
Accounts payable
|
$
|
—
|
|
|
$
|
9,983
|
|
|
$
|
—
|
|
|
$
|
9,983
|
|
Accounts payable - affiliates
|
247,488
|
|
|
1,248
|
|
|
(248,736
|
)
|
|
—
|
|
Revenues and production taxes payable
|
—
|
|
|
132,356
|
|
|
—
|
|
|
132,356
|
|
Accrued liabilities
|
10
|
|
|
167,659
|
|
|
—
|
|
|
167,669
|
|
Accrued interest payable
|
49,340
|
|
|
73
|
|
|
—
|
|
|
49,413
|
|
Deferred income taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Advances from joint interest partners
|
—
|
|
|
4,647
|
|
|
—
|
|
|
4,647
|
|
Other current liabilities
|
—
|
|
|
6,500
|
|
|
—
|
|
|
6,500
|
|
Total current liabilities
|
296,838
|
|
|
322,466
|
|
|
(248,736
|
)
|
|
370,568
|
|
Long-term debt
|
2,164,584
|
|
|
138,000
|
|
|
—
|
|
|
2,302,584
|
|
Deferred income taxes
|
—
|
|
|
813,329
|
|
|
(205,174
|
)
|
|
608,155
|
|
Asset retirement obligations
|
—
|
|
|
35,338
|
|
|
—
|
|
|
35,338
|
|
Liabilities held for sale
|
—
|
|
|
10,228
|
|
|
—
|
|
|
10,228
|
|
Other liabilities
|
—
|
|
|
3,160
|
|
|
—
|
|
|
3,160
|
|
Total liabilities
|
2,461,422
|
|
|
1,322,521
|
|
|
(453,910
|
)
|
|
3,330,033
|
|
Stockholders’ equity
|
|
|
|
|
|
|
|
Capital contributions from affiliates
|
—
|
|
|
3,369,895
|
|
|
(3,369,895
|
)
|
|
—
|
|
Common stock, $0.01 par value: 300,000,000 shares authorized; 139,583,990 shares issued and 139,076,064 shares outstanding
|
1,376
|
|
|
—
|
|
|
—
|
|
|
1,376
|
|
Treasury stock, at cost: 507,926 shares
|
(13,620
|
)
|
|
—
|
|
|
—
|
|
|
(13,620
|
)
|
Additional paid-in-capital
|
1,497,065
|
|
|
8,743
|
|
|
(8,743
|
)
|
|
1,497,065
|
|
Retained earnings
|
834,521
|
|
|
1,194,534
|
|
|
(1,194,534
|
)
|
|
834,521
|
|
Total stockholders’ equity
|
2,319,342
|
|
|
4,573,172
|
|
|
(4,573,172
|
)
|
|
2,319,342
|
|
Total liabilities and stockholders’ equity
|
$
|
4,780,764
|
|
|
$
|
5,895,693
|
|
|
$
|
(5,027,082
|
)
|
|
$
|
5,649,375
|
|
Condensed Consolidating Statement of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
|
Parent/
Issuer
|
|
Combined
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
(In thousands)
|
Revenues
|
|
|
|
|
|
|
|
Oil and gas revenues
|
$
|
—
|
|
|
$
|
635,505
|
|
|
$
|
—
|
|
|
$
|
635,505
|
|
Midstream revenues
|
—
|
|
|
35,406
|
|
|
—
|
|
|
35,406
|
|
Well services revenues
|
—
|
|
|
33,754
|
|
|
—
|
|
|
33,754
|
|
Total revenues
|
—
|
|
|
704,665
|
|
|
—
|
|
|
704,665
|
|
Operating expenses
|
|
|
|
|
|
|
|
Lease operating expenses
|
—
|
|
|
135,444
|
|
|
—
|
|
|
135,444
|
|
Midstream operating expenses
|
—
|
|
|
9,003
|
|
|
—
|
|
|
9,003
|
|
Well services operating expenses
|
—
|
|
|
17,009
|
|
|
—
|
|
|
17,009
|
|
Marketing, transportation and gathering expenses
|
—
|
|
|
40,366
|
|
|
—
|
|
|
40,366
|
|
Production taxes
|
—
|
|
|
56,565
|
|
|
—
|
|
|
56,565
|
|
Depreciation, depletion and amortization
|
—
|
|
|
476,331
|
|
|
—
|
|
|
476,331
|
|
Exploration expenses
|
—
|
|
|
1,785
|
|
|
—
|
|
|
1,785
|
|
Rig termination
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Impairment
|
—
|
|
|
4,684
|
|
|
—
|
|
|
4,684
|
|
General and administrative expenses
|
25,356
|
|
|
67,652
|
|
|
—
|
|
|
93,008
|
|
Total operating expenses
|
25,356
|
|
|
808,839
|
|
|
—
|
|
|
834,195
|
|
Loss on sale of properties
|
—
|
|
|
(1,303
|
)
|
|
—
|
|
|
(1,303
|
)
|
Operating loss
|
(25,356
|
)
|
|
(105,477
|
)
|
|
—
|
|
|
(130,833
|
)
|
Other income (expense)
|
|
|
|
|
|
|
|
Equity in loss of subsidiaries
|
(140,978
|
)
|
|
—
|
|
|
140,978
|
|
|
—
|
|
Net loss on derivative instruments
|
—
|
|
|
(105,317
|
)
|
|
—
|
|
|
(105,317
|
)
|
Interest expense, net of capitalized interest
|
(130,356
|
)
|
|
(9,949
|
)
|
|
—
|
|
|
(140,305
|
)
|
Gain on extinguishment of debt
|
4,741
|
|
|
—
|
|
|
—
|
|
|
4,741
|
|
Other income
|
137
|
|
|
23
|
|
|
—
|
|
|
160
|
|
Total other income (expense)
|
(266,456
|
)
|
|
(115,243
|
)
|
|
140,978
|
|
|
(240,721
|
)
|
Loss before income taxes
|
(291,812
|
)
|
|
(220,720
|
)
|
|
140,978
|
|
|
(371,554
|
)
|
Income tax benefit
|
48,796
|
|
|
79,742
|
|
|
—
|
|
|
128,538
|
|
Net loss
|
$
|
(243,016
|
)
|
|
$
|
(140,978
|
)
|
|
$
|
140,978
|
|
|
$
|
(243,016
|
)
|
Condensed Consolidating Statement of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2015
|
|
Parent/
Issuer
|
|
Combined
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
(In thousands)
|
Revenues
|
|
|
|
|
|
|
|
Oil and gas revenues
|
$
|
—
|
|
|
$
|
721,672
|
|
|
$
|
—
|
|
|
$
|
721,672
|
|
Midstream revenues
|
—
|
|
|
23,769
|
|
|
—
|
|
|
23,769
|
|
Well services and midstream revenues
|
—
|
|
|
44,294
|
|
|
—
|
|
|
44,294
|
|
Total revenues
|
—
|
|
|
789,735
|
|
|
—
|
|
|
789,735
|
|
Operating expenses
|
|
|
|
|
|
|
|
Lease operating expenses
|
—
|
|
|
144,481
|
|
|
—
|
|
|
144,481
|
|
Midstream operating expenses
|
—
|
|
|
6,198
|
|
|
—
|
|
|
6,198
|
|
Well services operating expenses
|
—
|
|
|
21,833
|
|
|
—
|
|
|
21,833
|
|
Marketing, transportation and gathering expenses
|
—
|
|
|
31,610
|
|
|
—
|
|
|
31,610
|
|
Production taxes
|
—
|
|
|
69,584
|
|
|
—
|
|
|
69,584
|
|
Depreciation, depletion and amortization
|
—
|
|
|
485,322
|
|
|
—
|
|
|
485,322
|
|
Exploration expenses
|
—
|
|
|
2,369
|
|
|
—
|
|
|
2,369
|
|
Rig termination
|
—
|
|
|
3,895
|
|
|
—
|
|
|
3,895
|
|
Impairment
|
—
|
|
|
46,109
|
|
|
—
|
|
|
46,109
|
|
General and administrative expenses
|
27,930
|
|
|
64,568
|
|
|
—
|
|
|
92,498
|
|
Total operating expenses
|
27,930
|
|
|
875,969
|
|
|
—
|
|
|
903,899
|
|
Operating loss
|
(27,930
|
)
|
|
(86,234
|
)
|
|
—
|
|
|
(114,164
|
)
|
Other income (expense)
|
|
|
|
|
|
|
|
Equity in earnings of subsidiaries
|
69,986
|
|
|
—
|
|
|
(69,986
|
)
|
|
—
|
|
Net gain on derivative instruments
|
—
|
|
|
210,376
|
|
|
—
|
|
|
210,376
|
|
Interest expense, net of capitalized interest
|
(138,166
|
)
|
|
(11,482
|
)
|
|
—
|
|
|
(149,648
|
)
|
Other income (expense)
|
5
|
|
|
(2,940
|
)
|
|
—
|
|
|
(2,935
|
)
|
Total other income (expense)
|
(68,175
|
)
|
|
195,954
|
|
|
(69,986
|
)
|
|
57,793
|
|
Income (loss) before income taxes
|
(96,105
|
)
|
|
109,720
|
|
|
(69,986
|
)
|
|
(56,371
|
)
|
Income tax benefit (expense)
|
55,857
|
|
|
(39,734
|
)
|
|
—
|
|
|
16,123
|
|
Net income (loss)
|
$
|
(40,248
|
)
|
|
$
|
69,986
|
|
|
$
|
(69,986
|
)
|
|
$
|
(40,248
|
)
|
Condensed Consolidating Statement of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014
|
|
Parent/
Issuer
|
|
Combined
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
(In thousands)
|
Revenues
|
|
|
|
|
|
|
|
Oil and gas revenues
|
$
|
—
|
|
|
$
|
1,304,004
|
|
|
$
|
—
|
|
|
$
|
1,304,004
|
|
Midstream revenues
|
—
|
|
|
11,614
|
|
|
—
|
|
|
11,614
|
|
Well services and midstream revenues
|
—
|
|
|
74,610
|
|
|
—
|
|
|
74,610
|
|
Total revenues
|
—
|
|
|
1,390,228
|
|
|
—
|
|
|
1,390,228
|
|
Operating expenses
|
|
|
|
|
|
|
|
Lease operating expenses
|
—
|
|
|
169,600
|
|
|
—
|
|
|
169,600
|
|
Midstream operating expenses
|
—
|
|
|
4,647
|
|
|
—
|
|
|
4,647
|
|
Well services operating expenses
|
—
|
|
|
45,605
|
|
|
—
|
|
|
45,605
|
|
Marketing, transportation and gathering expenses
|
—
|
|
|
29,133
|
|
|
—
|
|
|
29,133
|
|
Production taxes
|
—
|
|
|
127,648
|
|
|
—
|
|
|
127,648
|
|
Depreciation, depletion and amortization
|
—
|
|
|
412,334
|
|
|
—
|
|
|
412,334
|
|
Exploration expenses
|
—
|
|
|
3,064
|
|
|
—
|
|
|
3,064
|
|
Impairment
|
—
|
|
|
47,238
|
|
|
—
|
|
|
47,238
|
|
General and administrative expenses
|
23,528
|
|
|
68,778
|
|
|
—
|
|
|
92,306
|
|
Total operating expenses
|
23,528
|
|
|
908,047
|
|
|
—
|
|
|
931,575
|
|
Gain on sale of properties
|
—
|
|
|
186,999
|
|
|
—
|
|
|
186,999
|
|
Operating income (loss)
|
(23,528
|
)
|
|
669,180
|
|
|
—
|
|
|
645,652
|
|
Other income (expense)
|
|
|
|
|
|
|
|
Equity in earnings of subsidiaries
|
613,601
|
|
|
—
|
|
|
(613,601
|
)
|
|
—
|
|
Net gain on derivative instruments
|
—
|
|
|
327,011
|
|
|
—
|
|
|
327,011
|
|
Interest expense, net of capitalized interest
|
(147,230
|
)
|
|
(11,160
|
)
|
|
—
|
|
|
(158,390
|
)
|
Other income
|
5
|
|
|
190
|
|
|
—
|
|
|
195
|
|
Total other income (expense)
|
466,376
|
|
|
316,041
|
|
|
(613,601
|
)
|
|
168,816
|
|
Income before income taxes
|
442,848
|
|
|
985,221
|
|
|
(613,601
|
)
|
|
814,468
|
|
Income tax benefit (expense)
|
64,029
|
|
|
(371,620
|
)
|
|
—
|
|
|
(307,591
|
)
|
Net income
|
$
|
506,877
|
|
|
$
|
613,601
|
|
|
$
|
(613,601
|
)
|
|
$
|
506,877
|
|
Condensed Consolidating Statement of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
|
Parent/
Issuer
|
|
Combined
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
(In thousands)
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
Net loss
|
$
|
(243,016
|
)
|
|
$
|
(140,978
|
)
|
|
$
|
140,978
|
|
|
$
|
(243,016
|
)
|
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
Equity in loss of subsidiaries
|
140,978
|
|
|
—
|
|
|
(140,978
|
)
|
|
—
|
|
Depreciation, depletion and amortization
|
—
|
|
|
476,331
|
|
|
—
|
|
|
476,331
|
|
Gain on extinguishment of debt
|
(4,741
|
)
|
|
—
|
|
|
—
|
|
|
(4,741
|
)
|
Loss on sale of properties
|
—
|
|
|
1,303
|
|
|
—
|
|
|
1,303
|
|
Impairment
|
—
|
|
|
4,684
|
|
|
—
|
|
|
4,684
|
|
Deferred income taxes
|
(48,796
|
)
|
|
(79,742
|
)
|
|
—
|
|
|
(128,538
|
)
|
Derivative instruments
|
—
|
|
|
105,317
|
|
|
—
|
|
|
105,317
|
|
Stock-based compensation expenses
|
23,346
|
|
|
757
|
|
|
—
|
|
|
24,103
|
|
Deferred financing costs amortization and other
|
9,107
|
|
|
5,227
|
|
|
—
|
|
|
14,334
|
|
Working capital and other changes:
|
|
|
|
|
|
|
|
Change in accounts receivable
|
(250,737
|
)
|
|
207,931
|
|
|
30,883
|
|
|
(11,923
|
)
|
Change in inventory
|
—
|
|
|
254
|
|
|
—
|
|
|
254
|
|
Change in prepaid expenses
|
3
|
|
|
(298
|
)
|
|
—
|
|
|
(295
|
)
|
Change in other current assets
|
—
|
|
|
(305
|
)
|
|
—
|
|
|
(305
|
)
|
Change in other assets
|
100
|
|
|
(251
|
)
|
|
—
|
|
|
(151
|
)
|
Change in accounts payable and accrued liabilities
|
(230,518
|
)
|
|
247,562
|
|
|
(30,883
|
)
|
|
(13,839
|
)
|
Change in other current liabilities
|
—
|
|
|
4,490
|
|
|
—
|
|
|
4,490
|
|
Change in other liabilities and deferred credits
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
Net cash provided by (used in) operating activities
|
(604,274
|
)
|
|
832,292
|
|
|
—
|
|
|
228,018
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
Capital expenditures
|
—
|
|
|
(426,256
|
)
|
|
—
|
|
|
(426,256
|
)
|
Acquisitions of oil and gas properties
|
—
|
|
|
(781,522
|
)
|
|
—
|
|
|
(781,522
|
)
|
Proceeds from sale of properties
|
—
|
|
|
12,333
|
|
|
—
|
|
|
12,333
|
|
Costs related to sale of properties
|
—
|
|
|
(310
|
)
|
|
—
|
|
|
(310
|
)
|
Derivative settlements
|
—
|
|
|
121,977
|
|
|
—
|
|
|
121,977
|
|
Advances from joint interest partners
|
—
|
|
|
2,950
|
|
|
—
|
|
|
2,950
|
|
Net cash used in investing activities
|
—
|
|
|
(1,070,828
|
)
|
|
—
|
|
|
(1,070,828
|
)
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
Proceeds from revolving credit facility
|
—
|
|
|
1,407,000
|
|
|
—
|
|
|
1,407,000
|
|
Principal payments on revolving credit facility
|
—
|
|
|
(1,182,000
|
)
|
|
—
|
|
|
(1,182,000
|
)
|
Repurchase of senior unsecured notes
|
(435,907
|
)
|
|
—
|
|
|
—
|
|
|
(435,907
|
)
|
Proceeds from issuance of senior unsecured convertible notes
|
300,000
|
|
|
—
|
|
|
—
|
|
|
300,000
|
|
Deferred financing costs
|
(8,197
|
)
|
|
(930
|
)
|
|
—
|
|
|
(9,127
|
)
|
Proceeds from sale of common stock
|
766,670
|
|
|
—
|
|
|
—
|
|
|
766,670
|
|
Purchases of treasury stock
|
(2,330
|
)
|
|
—
|
|
|
—
|
|
|
(2,330
|
)
|
Investment in / capital contributions from subsidiaries
|
(16,573
|
)
|
|
16,573
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
603,663
|
|
|
240,643
|
|
|
—
|
|
|
844,306
|
|
Increase (decrease) in cash and cash equivalents
|
(611
|
)
|
|
2,107
|
|
|
—
|
|
|
1,496
|
|
Cash and cash equivalents at beginning of period
|
777
|
|
|
8,953
|
|
|
—
|
|
|
9,730
|
|
Cash and cash equivalents at end of period
|
$
|
166
|
|
|
$
|
11,060
|
|
|
$
|
—
|
|
|
$
|
11,226
|
|
Condensed Consolidating Statement of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2015
|
|
Parent/
Issuer
|
|
Combined
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
(In thousands)
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
Net income (loss)
|
$
|
(40,248
|
)
|
|
$
|
69,986
|
|
|
$
|
(69,986
|
)
|
|
$
|
(40,248
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|
Equity in earnings of subsidiaries
|
(69,986
|
)
|
|
—
|
|
|
69,986
|
|
|
—
|
|
Depreciation, depletion and amortization
|
—
|
|
|
485,322
|
|
|
—
|
|
|
485,322
|
|
Impairment
|
—
|
|
|
46,109
|
|
|
—
|
|
|
46,109
|
|
Deferred income taxes
|
(55,857
|
)
|
|
39,743
|
|
|
—
|
|
|
(16,114
|
)
|
Derivative instruments
|
—
|
|
|
(210,376
|
)
|
|
—
|
|
|
(210,376
|
)
|
Stock-based compensation expenses
|
24,762
|
|
|
510
|
|
|
—
|
|
|
25,272
|
|
Deferred financing costs amortization and other
|
4,964
|
|
|
7,335
|
|
|
—
|
|
|
12,299
|
|
Working capital and other changes:
|
|
|
|
|
|
|
|
Change in accounts receivable
|
(482
|
)
|
|
(47,553
|
)
|
|
156,496
|
|
|
108,461
|
|
Change in inventory
|
—
|
|
|
6,873
|
|
|
—
|
|
|
6,873
|
|
Change in prepaid expenses
|
19
|
|
|
1,809
|
|
|
—
|
|
|
1,828
|
|
Change in other current assets
|
—
|
|
|
6,489
|
|
|
—
|
|
|
6,489
|
|
Change in other assets
|
—
|
|
|
(950
|
)
|
|
—
|
|
|
(950
|
)
|
Change in accounts payable and accrued liabilities
|
156,039
|
|
|
(71,160
|
)
|
|
(156,496
|
)
|
|
(71,617
|
)
|
Change in other liabilities
|
—
|
|
|
6,500
|
|
|
—
|
|
|
6,500
|
|
Change in other liabilities and deferred credits
|
—
|
|
|
(33
|
)
|
|
—
|
|
|
(33
|
)
|
Net cash provided by operating activities
|
19,211
|
|
|
340,604
|
|
|
—
|
|
|
359,815
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
Capital expenditures
|
—
|
|
|
(819,847
|
)
|
|
—
|
|
|
(819,847
|
)
|
Acquisitions of oil and gas properties
|
—
|
|
|
(28,817
|
)
|
|
—
|
|
|
(28,817
|
)
|
Proceeds from sale of properties
|
—
|
|
|
1,075
|
|
|
—
|
|
|
1,075
|
|
Derivative settlements
|
—
|
|
|
370,410
|
|
|
—
|
|
|
370,410
|
|
Advances from joint interest partners
|
—
|
|
|
(1,969
|
)
|
|
—
|
|
|
(1,969
|
)
|
Net cash used in investing activities
|
—
|
|
|
(479,148
|
)
|
|
—
|
|
|
(479,148
|
)
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
Proceeds from revolving credit facility
|
—
|
|
|
630,000
|
|
|
—
|
|
|
630,000
|
|
Principal payments on revolving credit facility
|
—
|
|
|
(992,000
|
)
|
|
—
|
|
|
(992,000
|
)
|
Deferred financing costs
|
(11,045
|
)
|
|
(3,587
|
)
|
|
—
|
|
|
(14,632
|
)
|
Proceeds from sale of common stock
|
462,833
|
|
|
—
|
|
|
—
|
|
|
462,833
|
|
Purchases of treasury stock
|
(2,949
|
)
|
|
—
|
|
|
—
|
|
|
(2,949
|
)
|
Investment in / capital contributions from subsidiaries
|
(468,049
|
)
|
|
468,049
|
|
|
—
|
|
|
—
|
|
Net cash provided by (used in) financing activities
|
(19,210
|
)
|
|
102,462
|
|
|
—
|
|
|
83,252
|
|
Increase (decrease) in cash and cash equivalents
|
1
|
|
|
(36,082
|
)
|
|
—
|
|
|
(36,081
|
)
|
Cash and cash equivalents at beginning of period
|
776
|
|
|
45,035
|
|
|
—
|
|
|
45,811
|
|
Cash and cash equivalents at end of period
|
$
|
777
|
|
|
$
|
8,953
|
|
|
$
|
—
|
|
|
$
|
9,730
|
|
Condensed Consolidating Statement of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014
|
|
Parent/
Issuer
|
|
Combined
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
(In thousands)
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
Net income
|
$
|
506,877
|
|
|
$
|
613,601
|
|
|
$
|
(613,601
|
)
|
|
$
|
506,877
|
|
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
Equity in earnings of subsidiaries
|
(613,601
|
)
|
|
—
|
|
|
613,601
|
|
|
—
|
|
Depreciation, depletion and amortization
|
—
|
|
|
412,334
|
|
|
—
|
|
|
412,334
|
|
Gain on sale of properties
|
—
|
|
|
(186,999
|
)
|
|
—
|
|
|
(186,999
|
)
|
Impairment
|
—
|
|
|
47,238
|
|
|
—
|
|
|
47,238
|
|
Deferred income taxes
|
(64,029
|
)
|
|
371,486
|
|
|
—
|
|
|
307,457
|
|
Derivative instruments
|
—
|
|
|
(327,011
|
)
|
|
—
|
|
|
(327,011
|
)
|
Stock-based compensation expenses
|
20,701
|
|
|
601
|
|
|
—
|
|
|
21,302
|
|
Deferred financing costs amortization and other
|
4,549
|
|
|
6,479
|
|
|
—
|
|
|
11,028
|
|
Working capital and other changes:
|
|
|
|
|
|
|
|
Change in accounts receivable
|
(11
|
)
|
|
(65,657
|
)
|
|
82,370
|
|
|
16,702
|
|
Change in inventory
|
—
|
|
|
(3,776
|
)
|
|
—
|
|
|
(3,776
|
)
|
Change in prepaid expenses
|
21
|
|
|
(3,220
|
)
|
|
—
|
|
|
(3,199
|
)
|
Change in other current assets
|
—
|
|
|
(6,135
|
)
|
|
—
|
|
|
(6,135
|
)
|
Change in other assets
|
—
|
|
|
114
|
|
|
—
|
|
|
114
|
|
Change in accounts payable and accrued liabilities
|
84,044
|
|
|
75,049
|
|
|
(82,370
|
)
|
|
76,723
|
|
Change in other liabilities
|
—
|
|
|
(139
|
)
|
|
—
|
|
|
(139
|
)
|
Net cash provided by (used in) operating activities
|
(61,449
|
)
|
|
933,965
|
|
|
—
|
|
|
872,516
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
Capital expenditures
|
—
|
|
|
(1,354,281
|
)
|
|
—
|
|
|
(1,354,281
|
)
|
Acquisitions of oil and gas properties
|
—
|
|
|
(46,247
|
)
|
|
—
|
|
|
(46,247
|
)
|
Proceeds from sale of properties
|
—
|
|
|
324,852
|
|
|
—
|
|
|
324,852
|
|
Costs related to sale of properties
|
—
|
|
|
(2,337
|
)
|
|
—
|
|
|
(2,337
|
)
|
Derivative settlements
|
—
|
|
|
6,774
|
|
|
—
|
|
|
6,774
|
|
Advances from joint interest partners
|
—
|
|
|
(6,213
|
)
|
|
—
|
|
|
(6,213
|
)
|
Net cash used in investing activities
|
—
|
|
|
(1,077,452
|
)
|
|
—
|
|
|
(1,077,452
|
)
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
Proceeds from revolving credit facility
|
—
|
|
|
620,000
|
|
|
—
|
|
|
620,000
|
|
Principal payments on revolving credit facility
|
—
|
|
|
(455,570
|
)
|
|
—
|
|
|
(455,570
|
)
|
Deferred financing costs
|
—
|
|
|
(99
|
)
|
|
—
|
|
|
(99
|
)
|
Purchases of treasury stock
|
(5,309
|
)
|
|
—
|
|
|
—
|
|
|
(5,309
|
)
|
Investment in / capital contributions from subsidiaries
|
33,433
|
|
|
(33,433
|
)
|
|
—
|
|
|
—
|
|
Other
|
(176
|
)
|
|
—
|
|
|
—
|
|
|
(176
|
)
|
Net cash provided by financing activities
|
27,948
|
|
|
130,898
|
|
|
—
|
|
|
158,846
|
|
Decrease in cash and cash equivalents
|
(33,501
|
)
|
|
(12,589
|
)
|
|
—
|
|
|
(46,090
|
)
|
Cash and cash equivalents at beginning of period
|
34,277
|
|
|
57,624
|
|
|
—
|
|
|
91,901
|
|
Cash and cash equivalents at end of period
|
$
|
776
|
|
|
$
|
45,035
|
|
|
$
|
—
|
|
|
$
|
45,811
|
|
19. Supplemental Oil and Gas Disclosures
The supplemental data presented below reflects information for all of the Company’s oil and natural gas producing activities.
Capitalized Costs
The following table sets forth the capitalized costs related to the Company’s oil and natural gas producing activities:
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
2016
|
|
2015
(1)
|
|
(In thousands)
|
Proved oil and gas properties
(2)
|
$
|
6,476,833
|
|
|
$
|
5,655,759
|
|
Less: Accumulated depreciation, depletion, amortization and impairment
|
(1,886,732
|
)
|
|
(1,428,427
|
)
|
Proved oil and gas properties, net
|
4,590,101
|
|
|
4,227,332
|
|
Unproved oil and gas properties
|
819,735
|
|
|
628,642
|
|
Total oil and gas properties, net
|
$
|
5,409,836
|
|
|
$
|
4,855,974
|
|
__________________
|
|
(1)
|
At December 31, 2015, oil and gas properties exclude capitalized costs related to certain non-core assets that were held for sale (see Note 6 — Acquisitions and Divestitures).
|
|
|
(2)
|
Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of
$42.9 million
and
$30.7 million
at
December 31, 2016
and
2015
, respectively.
|
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Acquisition costs:
|
|
|
|
|
|
Proved oil and gas properties
|
$
|
781,522
|
|
|
$
|
28,737
|
|
|
$
|
37,048
|
|
Unproved oil and gas properties
|
672
|
|
|
3,226
|
|
|
30,891
|
|
Exploration costs
|
1,792
|
|
|
2,369
|
|
|
3,064
|
|
Development costs
|
207,766
|
|
|
433,735
|
|
|
1,437,923
|
|
Asset retirement costs
|
26,795
|
|
|
1,474
|
|
|
6,278
|
|
Total costs incurred
|
$
|
1,018,547
|
|
|
$
|
469,541
|
|
|
$
|
1,515,204
|
|
Results of Operations for Oil and Natural Gas Producing Activities
The following table sets forth the results of operations for oil and natural gas producing activities, which exclude straight-line depreciation, general and administrative expenses and interest expense, for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Revenues
(1)
|
$
|
625,233
|
|
|
$
|
721,672
|
|
|
$
|
1,304,004
|
|
Production costs
(1)
|
222,117
|
|
|
245,675
|
|
|
326,381
|
|
Depreciation, depletion and amortization
|
462,320
|
|
|
472,800
|
|
|
400,118
|
|
Exploration costs
|
1,785
|
|
|
2,369
|
|
|
3,064
|
|
Rig termination
|
—
|
|
|
3,895
|
|
|
—
|
|
Impairment
|
2,252
|
|
|
46,109
|
|
|
47,238
|
|
Income tax expense (benefit)
|
(23,665
|
)
|
|
(18,382
|
)
|
|
197,701
|
|
Results of operations for oil and natural gas producing activities
|
$
|
(39,576
|
)
|
|
$
|
(30,794
|
)
|
|
$
|
329,502
|
|
__________________
|
|
(1)
|
For the year ended December 31, 2016, revenues and production costs exclude bulk oil sales and purchases, respectively, of
$10.3 million
each.
|
20. Supplemental Oil and Gas Reserve Information — Unaudited
The reserve estimates at
December 31, 2016
,
2015
and
2014
presented in the table below are based on reports prepared by DeGolyer and MacNaughton, the Company’s independent reserve engineers, in accordance with the FASB’s authoritative guidance on oil and gas reserve estimation and disclosures. At
December 31, 2016
,
2015
and
2014
, all of the Company’s oil and natural gas producing activities were conducted within the continental United States.
The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Proved oil and natural gas reserves are the estimated quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.
Estimated Quantities of Proved Oil and Natural Gas Reserves — Unaudited
The following table sets forth the Company’s estimated net proved, proved developed and proved undeveloped reserves at
December 31, 2016
,
2015
and
2014
:
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbl)
|
|
Gas
(MMcf)
|
|
MBoe
|
2014
|
|
|
|
|
|
Proved reserves
|
|
|
|
|
|
Beginning balance
|
198,590
|
|
|
175,979
|
|
|
227,920
|
|
Revisions of previous estimates
|
(23,069
|
)
|
|
(12,290
|
)
|
|
(25,117
|
)
|
Extensions, discoveries and other additions
|
80,855
|
|
|
70,449
|
|
|
92,596
|
|
Sales of reserves in place
|
(7,640
|
)
|
|
(4,850
|
)
|
|
(8,448
|
)
|
Purchases of reserves in place
|
1,546
|
|
|
1,523
|
|
|
1,799
|
|
Production
|
(14,883
|
)
|
|
(10,691
|
)
|
|
(16,664
|
)
|
Net proved reserves at December 31, 2014
|
235,399
|
|
|
220,120
|
|
|
272,086
|
|
Proved developed reserves, December 31, 2014
|
127,340
|
|
|
114,016
|
|
|
146,343
|
|
Proved undeveloped reserves, December 31, 2014
|
108,059
|
|
|
106,104
|
|
|
125,743
|
|
2015
|
|
|
|
|
|
Proved reserves
|
|
|
|
|
|
Beginning balance
|
235,399
|
|
|
220,120
|
|
|
272,086
|
|
Revisions of previous estimates
|
(75,458
|
)
|
|
(55,065
|
)
|
|
(84,635
|
)
|
Extensions, discoveries and other additions
|
38,962
|
|
|
46,072
|
|
|
46,640
|
|
Sales of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
2,115
|
|
|
2,702
|
|
|
2,565
|
|
Production
|
(16,090
|
)
|
|
(14,001
|
)
|
|
(18,423
|
)
|
Net proved reserves at December 31, 2015
|
184,928
|
|
|
199,828
|
|
|
218,233
|
|
Proved developed reserves, December 31, 2015
|
127,445
|
|
|
120,789
|
|
|
147,577
|
|
Proved undeveloped reserves, December 31, 2015
|
57,483
|
|
|
79,039
|
|
|
70,656
|
|
2016
|
|
|
|
|
|
Proved reserves
|
|
|
|
|
|
Beginning balance
|
184,928
|
|
|
199,828
|
|
|
218,233
|
|
Revisions of previous estimates
|
11,713
|
|
|
116,539
|
|
|
31,136
|
|
Extensions, discoveries and other additions
|
10,790
|
|
|
24,520
|
|
|
14,876
|
|
Sales of reserves in place
|
(5,828
|
)
|
|
(10,839
|
)
|
|
(7,635
|
)
|
Purchases of reserves in place
|
50,164
|
|
|
100,629
|
|
|
66,936
|
|
Production
|
(15,174
|
)
|
|
(19,573
|
)
|
|
(18,436
|
)
|
Net proved reserves at December 31, 2016
|
236,593
|
|
|
411,104
|
|
|
305,110
|
|
Proved developed reserves, December 31, 2016
|
152,337
|
|
|
229,568
|
|
|
190,598
|
|
Proved undeveloped reserves, December 31, 2016
|
84,256
|
|
|
181,536
|
|
|
114,512
|
|
Revisions of Previous Estimates
In
2016
, the Company had a net positive revision of
31,136
MBoe, or
14%
of the beginning of the year estimated net proved reserves balance. This net positive revision was primarily due to larger completion designs and a higher gas to oil ratio, partially offset by the removal of proved undeveloped reserves that are no longer aligned with our anticipated five-year drilling plan and lower commodity prices.
In
2015
, the Company had a net negative revision of
84,635
MBoe, or
31%
of the beginning of the year estimated net proved reserves balance. This net negative revision was primarily due to the removal of proved undeveloped reserves that were not economic at the lower oil price or were no longer aligned with the Company’s anticipated five-year drilling plan. This resulted in
259
gross (
190.8
net) proved undeveloped locations with
71,495
MBoe of reserves being removed from the
December 31, 2015
estimated net proved reserves balance, most significantly, removing proved undeveloped reserves outside of the Company’s core acreage within the Williston Basin that were uneconomic as of December 31,
2015
due to the lower oil price. The remaining negative revision was primarily attributable to the impact of price on producing life, partially offset by positive revisions due to performance and operating costs.
In
2014
, the Company had a net negative revision of
25,117
MBoe, or
11%
of the beginning of the year estimated net proved reserves balance. This net negative revision was primarily due to the removal of proved undeveloped reserves not aligned with the Company’s anticipated five-year drilling plan, which was adjusted to allocate a greater focus on higher rates-
of-return areas of the Bakken and Three Forks formations. This resulted in
80
gross (
56.2
net) proved undeveloped locations with
21,411
MBoe of reserves being removed from the
December 31, 2014
estimated net proved reserves balance.
Extensions, Discoveries and Other Additions
In
2016
, the Company had a total of
14,876
MBoe of additions due to extensions and discoveries. An estimated
6,214
MBoe of these extensions and discoveries were associated with new producing wells at
December 31, 2016
, with
100%
of these reserves from wells producing in the Bakken or Three Forks formations. An additional
6,493
MBoe of proved undeveloped reserves were added in the Williston Basin associated with the Company’s
2016
operated and non-operated drilling program and anticipated five-year drilling plan, with
100%
of these proved undeveloped reserves in the Bakken or Three Forks formations.
In
2015
, the Company had a total of
46,640
MBoe of additions due to extensions and discoveries. An estimated
20,362
MBoe of these extensions and discoveries were associated with new producing wells at
December 31, 2015
, with
100%
of these reserves from wells producing in the Bakken or Three Forks formations. An additional
26,278
MBoe of proved undeveloped reserves were added in the Williston Basin associated with the Company’s
2015
operated and non-operated drilling program and anticipated five-year drilling plan, with
100%
of these proved undeveloped reserves in the Bakken or Three Forks formations.
In
2014
, the Company had a total of
92,596
MBoe of additions due to extensions and discoveries. An estimated
34,404
MBoe of these extensions and discoveries were associated with new producing wells at
December 31, 2014
, with
100%
of these reserves from wells producing in the Bakken or Three Forks formations. An additional
58,192
MBoe of proved undeveloped reserves were added in the Williston Basin associated with the Company’s
2014
operated and non-operated drilling program and anticipated five-year drilling plan, with
100%
of these proved undeveloped reserves in the Bakken or Three Forks formations.
Sales of Reserves in Place
In 2016 and 2014, the Company divested
7,635
MBoe and
8,448
MBoe, respectively, of reserves associated with its traded acreage and sold wells (see Note 6 — Acquisitions and Divestitures). In 2015, the Company did not have any sales of reserves.
Purchases of Reserves in Place
In 2016, the Company purchased
66,936
MBoe of estimated net proved reserves from acquisitions (see Note 6 — Acquisitions and Divestitures). In 2015 and 2014, the Company purchased estimated net proved reserves of
2,565
MBoe and
1,799
, respectively, from acquisitions of additional working interests in its existing properties in the Williston Basin.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves — Unaudited
The Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at
10%
per annum to reflect timing of future cash flows. Production costs do not include DD&A of capitalized acquisition, exploration and development costs.
The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were
$42.60
/Bbl for oil and
$2.47
/MMBtu for natural gas,
$50.16
/Bbl for oil and
$2.63
/MMBtu for natural gas and
$95.28
/Bbl for oil and
$4.35
/MMBtu for natural gas for the years ended
December 31, 2016
,
2015
and
2014
, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Future operating costs, production taxes and capital costs were based on current costs as of each year-end.
The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at
December 31, 2016
,
2015
and
2014
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
Future cash inflows
|
$
|
9,426,963
|
|
|
$
|
8,582,831
|
|
|
$
|
21,656,832
|
|
Future production costs
|
(3,996,657
|
)
|
|
(3,842,517
|
)
|
|
(7,094,426
|
)
|
Future development costs
|
(784,727
|
)
|
|
(909,562
|
)
|
|
(2,563,062
|
)
|
Future income tax expense
|
(279,345
|
)
|
|
(225,662
|
)
|
|
(3,188,389
|
)
|
Future net cash flows
|
4,366,234
|
|
|
3,605,090
|
|
|
8,810,955
|
|
10% annual discount for estimated timing of cash flows
|
(1,883,169
|
)
|
|
(1,690,760
|
)
|
|
(4,829,294
|
)
|
Standardized measure of discounted future net cash flows
|
$
|
2,483,065
|
|
|
$
|
1,914,330
|
|
|
$
|
3,981,661
|
|
The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
(In thousands)
|
January 1
|
$
|
1,914,330
|
|
|
$
|
3,981,661
|
|
|
$
|
3,727,559
|
|
Net changes in prices and production costs
|
(367,527
|
)
|
|
(3,201,195
|
)
|
|
(588,212
|
)
|
Net changes in future development costs
|
69,992
|
|
|
150,333
|
|
|
(61,760
|
)
|
Sales of oil and natural gas, net
|
(403,739
|
)
|
|
(477,755
|
)
|
|
(979,938
|
)
|
Extensions
|
165,926
|
|
|
409,838
|
|
|
1,751,007
|
|
Discoveries
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
533,505
|
|
|
14,378
|
|
|
38,035
|
|
Sales of reserves in place
|
(57,770
|
)
|
|
—
|
|
|
(251,002
|
)
|
Revisions of previous quantity estimates
|
333,398
|
|
|
(946,729
|
)
|
|
(604,651
|
)
|
Previously estimated development costs incurred
|
91,518
|
|
|
216,981
|
|
|
249,926
|
|
Accretion of discount
|
(36,303
|
)
|
|
548,141
|
|
|
548,690
|
|
Net change in income taxes
|
202,272
|
|
|
1,391,358
|
|
|
259,592
|
|
Changes in timing and other
|
37,463
|
|
|
(172,681
|
)
|
|
(107,585
|
)
|
December 31
|
$
|
2,483,065
|
|
|
$
|
1,914,330
|
|
|
$
|
3,981,661
|
|
21. Quarterly Financial Data — Unaudited
The Company’s results of operations by quarter for the years ended
December 31, 2016
and
2015
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2016
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
(In thousands)
|
Revenues
|
$
|
130,283
|
|
|
$
|
179,080
|
|
|
$
|
177,311
|
|
|
$
|
217,991
|
|
Operating loss
|
(75,215
|
)
|
|
(28,214
|
)
|
|
(25,702
|
)
|
|
(1,702
|
)
|
Net loss
|
(64,455
|
)
|
|
(89,931
|
)
|
|
(33,942
|
)
|
|
(54,688
|
)
|
Basic loss per share
|
(0.40
|
)
|
|
(0.51
|
)
|
|
(0.19
|
)
|
|
(0.25
|
)
|
Diluted loss per share
|
(0.40
|
)
|
|
(0.51
|
)
|
|
(0.19
|
)
|
|
(0.25
|
)
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2015
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
(In thousands)
|
Revenues
|
$
|
180,387
|
|
|
$
|
230,046
|
|
|
$
|
197,235
|
|
|
$
|
182,067
|
|
Operating loss
|
(33,635
|
)
|
|
(7,437
|
)
|
|
(19,926
|
)
|
|
(53,166
|
)
|
Net income (loss)
|
(18,041
|
)
|
|
(53,230
|
)
|
|
27,055
|
|
|
3,968
|
|
Basic earnings (loss) per share
|
(0.17
|
)
|
|
(0.39
|
)
|
|
0.20
|
|
|
0.03
|
|
Diluted earnings (loss) per share
|
(0.17
|
)
|
|
(0.39
|
)
|
|
0.20
|
|
|
0.03
|
|