Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with other sections of this report, including: “Business” in Item 1, “Selected Financial Data” in Item 6 and “Financial Statements and Supplementary Data” in Item 8. Our discussion and analysis includes the following subjects:
•
Overview;
•
Consolidated Results of Operations;
•
Liquidity and Capital Resources;
•
Valuation Allowance; and
•
Critical Accounting Policies and Estimates.
Overview
We are an oil and natural gas company with a principal focus on exploration and production activities in the U.S. Mid-Continent and North Park Basin of Colorado.
Basis of Presentation
We emerged from Chapter 11 and applied fresh start accounting in October 2016; however, this reorganization did not require the divestiture of any of our oil and natural gas properties. As a result, certain operating results and key operating performance measures, including those related to production, average oil and natural gas selling prices, revenues and lease operating expenses, were not significantly impacted and certain of the combined operating results of the Predecessor 2016 Period and the Successor 2016 Period during the year ended December 31, 2016, are still comparable with certain operating results in the other years presented. Accordingly, we believe that discussing the combined results of operations and cash flows of the Predecessor Company and the Successor Company for the two periods in 2016 is useful when analyzing certain performance measures. For items that are not comparable, we have included additional analysis to supplement the discussion.
Operational Activities
Operational activities for the years ended December 31, 2018, and 2017 include the following:
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Year Ended December 31,
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2018
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2017
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Gross Wells Drilled(2)
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Net Wells Drilled(2)
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Average Rigs Drilling
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Gross Wells Drilled(2)
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Net Wells Drilled(2)
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Average Rigs Drilling
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Area
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Mid-Continent (1)
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22
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8.0
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1.7
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20
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14.1
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2.3
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North Park Basin
|
14
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14.0
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0.7
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7
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7.0
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0.6
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Total
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36
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22.0
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2.4
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27
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21.1
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2.9
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____________________
1.
During the years ended December 31, 2018 and 2017, we drilled 15 and three wells, respectively, under the drilling participation agreement. Under this agreement, we are receiving a 20% net working interest after funding 10% of the drilling and completion costs related to the subject wells. The Counterparty to the drilling participation agreement has been billed costs totaling
$65.2 million for drilling and completion activity from inception through December 31, 2018, under the initial $100.0 million tranche of the agreement.
2.
Includes wells with a rig release date during the years ended December 31, 2018 or 2017, respectively.
Total production for 2018 was comprised of approximately 28.2% oil, 48.9% natural gas and 22.9% NGLs compared to 27.9% oil, 49.5% natural gas and 22.6% NGLs in 2017.
Recent Events
•
On January 28, 2019,
the Board appointed Paul D. McKinney as President and Chief Executive Officer, effective January 29, 2019. Mr. McKinney succeeds Mr. William M. Griffin, Jr., who continues to serve on the Board.
•
On November 2, 2018, we acquired certain oil and natural gas properties, right
s and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas as discussed further in "—Acquisitions and Divestitures" below.
•
On November 1, 2018, we sold substantially all of our oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, together with 13,125,000 common units of the Trust as discussed further in "
—Acquisitions and Divestitures" below.
•
During the second half of 2018, the Board reviewed our strategic options which could have included a possible sale of the Company or certain significant assets
, and conducted a complete and thorough review of our assets and operating strategies, including capital expenditures and drilling programs, and overall cost structure. On September 10, 2018, the Board announced it had concluded the formal strategic review process following the thorough evaluation of multiple potential transactions, all of which the Board believed significantly undervalued either the Company or its resources.
•
As a result of the proxy contest discussed further in "Note
18 - Proxy Contest", the size of the Board was expanded to eight directors in June 2018. The Board now consists of previous directors Sylvia K. Barnes, David J. Kornder and William M. Griffin, Jr., and newly elected members Bob G. Alexander, Jonathan Christodoro, Jonathan Frates, John J. "Jack" Lipinski and Randolph C. Read.
Outlook
After completing the strategic review process noted above, the Board concluded that our future course is to develop our inventory of NW STACK and North Park Basin drilling opportunities and pursue value enhancing opportunities in the Mid-Continent. We will also pursue accretive acquisitions of strategic assets that provide high quality production and development upside. Focusing on cost reductions, margin improvements and opportunistic divestment of core and non-core properties will also be a part of our plan moving forward. Based on these strategic objectives, we intend to spend between $160.0 million and $180.0 million in our 2019 capital budget plan. The substantial majority of these budgeted expenditures is designated for drilling and completion activities. Based on our 2019 capital spending plans, we estimate that our production will experience a 5%- 6% decline. We will continue to monitor the changing market conditions and the results of our operations and will take measures to help achieve our strategic objectives, enhance shareholder value and improve our competitiveness in the marketplace. We will endeavor to keep our capital spending within or very close to our projected cash flows from operations subject to changing industry conditions or events.
Consolidated Results of Operations
The majority of our consolidated revenues and cash flow are generated from the production and sale of oil, natural gas and NGLs. Our revenues, profitability and future growth depend substantially on prevailing prices received for our production, the quantity of oil, natural gas and NGLs we produce, our ability to find and economically develop and produce our reserves, and changes in the fair value of our commodity derivative contracts. Prices for oil, natural gas and NGLs fluctuate widely and are difficult to predict. To provide information on the general trend in pricing, the average annual NYMEX prices for oil and natural gas for recent years are presented in the table below:
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Year Ended December 31,
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2018
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2017
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2016
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2015
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2014
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Oil (per Bbl)
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$
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64.90
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$
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50.85
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$
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43.47
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$
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48.75
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$
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92.91
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Natural gas (per Mcf)
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$
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3.07
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$
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3.02
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$
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2.55
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$
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2.62
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$
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4.26
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In order to reduce our exposure to price fluctuations, we have historically entered into commodity derivative contracts for a portion of our anticipated future oil and natural gas production as discussed in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” Reducing the Company’s exposure to price volatility helps mitigate the risk that we will not have adequate funds available for our capital expenditure programs. During periods where the strike prices for our commodity derivative contracts are below market prices at the time of settlement, we may not fully benefit from increases in the market price of oil and natural gas. Conversely, during periods of declining market prices of oil and natural gas, our commodity derivative contracts may partially offset declining revenues and cash flow to the extent strike prices for our contracts are above market prices at the time of settlement. At December 31, 2018, we have no oil derivative contracts in place and have natural gas derivatives in place through March of 2019.
Acquisitions and Divestitures of Oil and Gas Properties
Divestiture of Permian Basin Properties.
On November 1, 2018, we sold substantially all of our oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, primarily located in Andrews County, TX, along with all of our 13,125,000 common units representing a 25% equity interest in the Permian Trust, to an independent third party for $14.5 million in cash, subject to certain remaining post-closing adjustments, and reduced our asset retirement obligations by approximately $26.9 million. The CBP assets and interest in the Permian Trust include 1,066 producing wells within the Permian Trust's area of mutual interest, certain wells not associated with the Permian Trust, a field office, and all equipment, inventory and yards associated with our CBP operations. As a result of this divestiture, we no longer have any obligations associated with the Permian Trust. This transaction did not result in a significant alteration of the relationship between our capitalized costs and proved reserves and, accordingly, the divestiture was accounted for as an adjustment to the full cost pool with no gain or loss recognized on the sale.
Acquisition of Oil and Natural Gas Interests.
On November 2, 2018, we acquired certain interests in oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas for approximately $22.5 million in net consideration, net of post-closing adjustments, and assumed asset retirement obligations of approximately $6.4 million. The acquired assets primarily consist of interests in 1,199 producing wells, approximately 80% of which we operate, an additional 11.1% working interest in approximately 397,000 gross (44,000 net) acres across the Mid-Continent, and an additional 13.2% working interest ownership in our saltwater gathering and disposal system in the Mississippian Lime. This acquisition is expected to increase total production for existing producing properties by approximately 10%.
Acquisition of NW STACK Properties.
On February 10, 2017, we acquired assets consisting of approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.8 million in cash, net of post-closing adjustments. Also included in the acquisition were working interests in four wells previously drilled on the acreage.
2017 Oil and Natural Gas Property Divestitures.
In 2017, we divested various non-core oil and natural gas properties for approximately $17.1 million in cash. All of these divestitures were accounted for as adjustments to the full cost pool with no gain or loss recognized.
Divestiture of WTO Properties and Release from Treating Agreement.
In January 2016, we paid $11.0 million in cash and transferred ownership of substantially all of our oil and natural gas properties and midstream assets located in the Piñon field in the WTO to Occidental and were released from all past, current and future claims and obligations under an existing 30-year treating agreement with Occidental. In connection with this transfer, the Predecessor Company recognized a loss of approximately $89.1 million on the termination of the treating agreement and the cease-use of transportation agreements that supported production from the Piñon field and reduced its asset retirement obligations associated with its oil and natural gas properties by $34.1 million.
Oil, Natural Gas and NGL Production and Pricing
The table below presents production and pricing information for the years ended December 31, 2018, and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined results for the full year ended December 31, 2016.
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Successor
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Predecessor
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Combined
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Year Ended December 31,
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Year Ended December 31,
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Period from October 2, 2016 through December 31,
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Period from January 1, 2016 through October 1,
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Year Ended December 31,
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2018
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2017
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2016
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2016
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2016
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Production data (in thousands)
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Oil (MBbls)
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3,477
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4,157
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1,214
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4,315
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5,529
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NGL (MBbls)
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2,829
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3,376
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999
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3,358
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4,357
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Natural gas (MMcf)
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36,175
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|
44,237
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12,771
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|
44,124
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56,895
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Total volumes (MBoe)
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12,335
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14,906
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|
4,342
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|
15,027
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|
19,369
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Average daily total volumes (MBoe/d)
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33.8
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|
40.8
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|
47.7
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|
54.6
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|
|
52.9
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Average prices—as reported(1)
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Oil (per Bbl)
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$
|
61.73
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$
|
48.72
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$
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47.03
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$
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36.85
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|
|
$
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39.09
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NGL (per Bbl)
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$
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23.72
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$
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18.16
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|
$
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14.77
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$
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12.67
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|
|
$
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13.15
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Natural gas (per Mcf)
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$
|
1.85
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|
$
|
2.09
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|
$
|
2.07
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$
|
1.78
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|
|
$
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1.84
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Total (per Boe)
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$
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28.27
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|
$
|
23.90
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|
$
|
22.64
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|
$
|
18.63
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|
|
$
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19.53
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Average prices—including impact of derivative contract settlements(2)
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Oil (per Bbl)
|
$
|
51.35
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|
$
|
49.75
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|
$
|
54.59
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|
$
|
51.05
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|
|
$
|
51.83
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NGL (per Bbl)
|
$
|
23.72
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|
$
|
18.16
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|
$
|
14.77
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|
$
|
12.67
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|
|
$
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13.15
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Natural gas (per Mcf)
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$
|
1.89
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|
$
|
2.15
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|
$
|
1.96
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$
|
1.77
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|
|
$
|
1.81
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Total (per Boe)
|
$
|
25.47
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$
|
24.38
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$
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24.41
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$
|
22.70
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$
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23.08
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____________________
1.
Prices represent actual average prices for the periods presented and do not include the impact of derivative transactions.
2.
Excludes settlements of commodity derivative contracts prior to their contractual maturity, if any.
For a discussion of reserves, PV-10 and reconciliation to Standardized Measure, see “Business— Primary Operations—Proved Reserves” in Item 1 of this report.
The table below presents production by area of operation for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period, and illustrates the impact of (i) natural declines in existing producing wells in the Mid-Continent, (ii) the Permian Divestiture in November 2018 and drilling no new wells in the Permian and other regions during 2018, 2017 and 2016, and (ii) continued development of the North Park Basin properties, which were acquired in December 2015 and the NW STACK, which was acquired in February 2017.
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Successor
|
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Predecessor
|
|
|
|
Year Ended December 31,
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|
|
|
Year Ended December 31,
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|
|
|
Period from October 2, 2016 through December 31,
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|
|
|
Period from January 1, 2016 through October 1,
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|
|
|
2018
|
|
|
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2017
|
|
|
|
2016
|
|
|
|
2016
|
|
|
|
Production (MBoe)
|
|
% of Total Production
|
|
Production (MBoe)
|
|
% of Total Production
|
|
Production (MBoe)
|
|
% of Total Production
|
|
Production (MBoe)
|
|
% of Total Production
|
Mississippian Lime
|
10,003
|
|
81.1
|
%
|
|
12,838
|
|
86.2
|
%
|
|
4,018
|
|
92.5
|
%
|
|
14,119
|
|
94.0
|
%
|
NW STACK
|
925
|
|
7.5
|
%
|
|
882
|
|
5.9
|
%
|
|
—
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|
—
|
%
|
|
—
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|
—
|
%
|
North Park Basin
|
1,034
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|
8.4
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%
|
|
673
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|
4.5
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%
|
|
180
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|
4.1
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%
|
|
320
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|
2.1
|
%
|
Permian Basin
|
373
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|
3.0
|
%
|
|
513
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|
3.4
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%
|
|
144
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|
3.4
|
%
|
|
489
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|
3.3
|
%
|
Other
|
—
|
|
—
|
%
|
|
—
|
|
—
|
%
|
|
—
|
|
—
|
%
|
|
99
|
|
0.6
|
%
|
Total
|
12,335
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|
100.0
|
%
|
|
14,906
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|
100.0
|
%
|
|
4,342
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|
100.0
|
%
|
|
15,027
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|
100.0
|
%
|
Revenues
Consolidated revenues for the years ended December 31, 2018, and 2017, the Successor 2016 Period, the Predecessor 2016 Period, and the combined results for the year ended December 31, 2016 are presented in the table below (in thousands).
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|
|
|
|
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|
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|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
Predecessor
|
|
Combined
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
2016
|
|
2016
|
Revenues
|
|
|
|
|
|
|
|
|
|
Oil
|
$
|
214,651
|
|
$
|
202,539
|
|
$
|
57,093
|
|
$
|
159,023
|
|
$
|
216,116
|
NGL
|
67,111
|
|
61,322
|
|
14,756
|
|
42,541
|
|
57,297
|
Natural gas
|
66,964
|
|
92,349
|
|
26,458
|
|
78,407
|
|
104,865
|
Other
|
669
|
|
1,089
|
|
149
|
|
13,838
|
|
13,987
|
Total revenues
|
$
|
349,395
|
|
$
|
357,299
|
|
$
|
98,456
|
|
$
|
293,809
|
|
$
|
392,265
|
Variances in oil, natural gas and NGL revenues attributable to changes in the average prices received for our production and total production volumes sold for the years ended December 31, 2018 and 2017 are shown in the table below (in thousands):
|
|
|
|
|
|
|
|
|
|
2016 oil, natural gas and NGL revenues (supplemental pro forma combined)
|
$
|
378,278
|
Change due to production volumes in 2017
|
(90,073)
|
Change due to average prices in 2017
|
68,005
|
2017 oil, natural gas and NGL revenues
|
356,210
|
Change due to production volumes in 2018
|
(59,897)
|
Change due to average prices in 2018
|
52,413
|
2018 oil, natural gas and NGL revenues
|
$
|
348,726
|
|
|
|
|
|
|
|
|
Oil, natural gas and NGL revenues decreased by a combined $7.5 million, or 2.1% for the year ended December 31, 2018, compared to 2017 due largely to a 2.6 MMBoe decrease in total production, primarily resulting from natural declines in existing producing wells and a decline in prices received for our natural gas production. This decrease was partially offset by an increase in average prices received for our oil and NGL production.
Oil, natural gas and NGL sales decreased by a combined $22.1 million, or 5.8% for the year ended December 31, 2017, compared to 2016 due largely to a 4.5 MMBoe decrease in total production, primarily resulting from natural declines in existing producing wells and fewer wells brought on production. This decrease was partially offset by an increase in average prices received for our oil, NGL and natural gas production. Additionally, the average prices received in the 2017 period include the full effect of the Successor Company’s election to include transportation deductions in revenues as discussed in “—Expenses” below, whereas the combined 2016 period only includes the impact of this election for the Successor 2016 Period.
Other revenues primarily include drilling and oilfield services and marketing and midstream sales, which decreased in 2017 compared to 2016 largely due to discontinuing all remaining drilling and oilfield services operations in 2016, and transferring substantially all oil and natural gas properties and midstream assets located in the Piñon field in the WTO to Occidental in January 2016.
Expenses
Consolidated expenses for the years ended December 31, 2018, and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined results for the year ended December 31, 2016 are presented below.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
Predecessor
|
|
Combined
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
2016
|
|
2016
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
Production
|
$
|
92,703
|
|
$
|
102,728
|
|
24,997
|
|
129,608
|
|
$
|
154,605
|
Production taxes
|
19,470
|
|
13,644
|
|
2,643
|
|
6,107
|
|
8,750
|
Depreciation and depletion—oil and natural gas
|
127,281
|
|
118,035
|
|
36,061
|
|
90,978
|
|
127,039
|
Depreciation and amortization—other
|
11,982
|
|
13,852
|
|
3,922
|
|
21,323
|
|
25,245
|
Impairment
|
4,170
|
|
4,019
|
|
319,087
|
|
718,194
|
|
1,037,281
|
General and administrative
|
41,666
|
|
76,024
|
|
9,837
|
|
116,091
|
|
125,928
|
Accelerated vesting of employment compensation
|
6,545
|
|
—
|
|
—
|
|
—
|
|
—
|
Proxy contest
|
7,139
|
|
—
|
|
—
|
|
—
|
|
—
|
Terminated merger costs
|
—
|
|
8,162
|
|
—
|
|
—
|
|
—
|
Employee termination benefits
|
32,657
|
|
4,815
|
|
12,334
|
|
18,356
|
|
30,690
|
Loss (gain) on derivative contracts
|
17,155
|
|
(24,090)
|
|
25,652
|
|
4,823
|
|
30,475
|
Loss on settlement of contract
|
—
|
|
—
|
|
—
|
|
90,184
|
|
90,184
|
Other operating expense
|
(998)
|
|
479
|
|
268
|
|
4,348
|
|
4,616
|
Total expenses
|
$
|
359,770
|
|
$
|
317,668
|
|
$
|
434,801
|
|
$
|
1,200,012
|
|
$
|
1,634,813
|
Production expense includes but is not limited to, lease operating expense and ad valorem taxes on our oil and gas properties. Production expenses for 2018 decreased $10.0 million, or 9.8% from 2017. Production costs per Boe increased to $7.52 per Boe for the 2018 period from $6.89 per Boe in 2017, primarily due to the decrease in total production noted above.
Production expenses for 2017 decreased $51.9 million, or 33.6% from combined 2016 production expenses. Production costs per Boe decreased to $6.89 per Boe for the 2017 period from $7.98 per Boe in 2016, primarily due to (i) the Successor Company’s presentation of transportation costs totaling $29.1 million as a reduction from revenues for the year ended December 31, 2017, compared to the presentation of only $7.4 million of transportation costs as a reduction from revenues in the Successor 2016 Period with the remaining 2016 transportation costs of $26.2 million being presented as production expenses by the Predecessor Company, and (ii) controlled reductions in expenditures for electricity, chemicals and various other costs.
Production taxes, which are levied by the state governments in the areas in which we operate, typically change in direct correlation with increases or decreases in our oil, natural gas and NGL revenues. However, production taxes as a percentage of oil, natural gas and NGL revenue increased to approximately 5.6% in 2018, compared to 3.8% for 2017, and 2.3% for 2016. These increases were primarily due to fewer wells having the benefit of tax credits in 2018 and 2017 compared to 2016 due to the loss of certain horizontal tax credits, which caused previous rates to increase back to statutory rates for certain wells.
Depreciation and depletion for oil and natural gas properties increased by $9.2 million for the year ended December 31, 2018 compared to 2017 due to an increase in the average depreciation and depletion rate to $10.32 per Boe in 2018 compared to an average rate of $7.92 in 2017. The increase in the rate primarily resulted from continuing to incur higher actual drilling and completion costs per Boe during 2018 compared to the lower rates experienced in 2017 which resulted from the significant ceiling test write-down in the fourth quarter of 2016. Additionally, more capital is being allocated to develop our North Park Basin oil asset where future development costs are higher. As a result, average depletion rates have increased and may continue to increase as we develop this area.
Depreciation and depletion for oil and natural gas properties decreased by $9.0 million for the year ended December 31, 2017 compared to the combined 2016 periods, primarily due to the decrease in production. This decrease was partially
offset by an increase in the average depreciation and depletion rate to $7.92 per Boe in 2017 compared to an average rate of $6.56 per Boe for the combined 2016 periods. This increase in the average rate primarily resulted from (i) incurring higher actual drilling and completion costs per Boe during the 2017 period compared to the rate per Boe calculated at December 31, 2016 following the significant ceiling test write-down incurred in the fourth quarter of 2016, (ii) a shift of more capital to develop our North Park Basin oil asset where the anticipated future development costs are likewise expected to be higher than the 2016 rate, and (iii) a $3.1 million increase in accretion for the year ended December 31, 2017, compared to the combined 2016 periods, primarily due to the Successor Company recording a higher fresh start valuation for asset retirement obligations on the Emergence Date.
Depreciation and depletion for oil and natural gas properties for the Successor 2016 Period was recorded at an average depreciation and depletion rate of $8.31 per Boe compared to a rate of $6.05 per Boe for the Predecessor 2016 Period, which reflects an increase in reserve values due to fresh start valuation adjustments recorded for reserves as of October 1, 2016, and the full cost ceiling impairments recorded in the Successor 2016 Period.
Depreciation and amortization for non-oil and gas properties decreased across all periods primarily due to (i) the sale of substantially all drilling assets during 2016 and 2015 after discontinuing drilling operations, (ii) the sale of a property located in downtown Oklahoma City, Oklahoma as well as other corporate assets, and (iii) the divestiture of the WTO properties and related assets.
Impairment expense for the years ended December 31, 2018 and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined year ended December 31, 2016 consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
Predecessor
|
|
Combined
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
2016
|
|
2016
|
Impairment
|
|
|
|
|
|
|
|
|
|
Full cost pool ceiling limitation
|
$
|
—
|
|
$
|
—
|
|
$
|
319,087
|
|
$
|
657,392
|
|
$
|
976,479
|
Drilling assets
|
22
|
|
4,019
|
|
—
|
|
3,511
|
|
3,511
|
Electrical infrastructure assets
|
—
|
|
—
|
|
—
|
|
55,600
|
|
55,600
|
Midstream assets
|
4,148
|
|
—
|
|
—
|
|
1,691
|
|
1,691
|
|
|
|
|
|
|
|
|
|
|
Total impairment
|
$
|
4,170
|
|
$
|
4,019
|
|
$
|
319,087
|
|
$
|
718,194
|
|
$
|
1,037,281
|
Full cost pool impairment.
Upon the application of fresh start accounting, the value of the Successor Company full cost pool was determined based upon forward strip oil and natural gas prices as of the Emergence Date. Because these prices were higher than the SEC prices used in the full cost ceiling limitation calculation at December 31, 2016, the Successor Company incurred a ceiling test impairment of $319.1 million.
Full cost pool impairment recorded for the Predecessor Company in 2016 was due to full cost ceiling limitations recognized in each of the first three quarters of 2016. The impairments recorded in the first two quarters of 2016 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued through the first half of 2016. The impairment recorded in the third quarter of 2016 resulted primarily from downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes. The decrease in projected production volumes resulted from steeper than anticipated well production decline rates for Mississippian horizontal wells in areas with increased natural fracture density and that had been developed with three or more horizontal wells per section as inter-well pressure communication had more impact on well performance than originally forecasted. Additionally, changing pressure conditions in our Mississippian wells producing with artificial lift resulted in increased production decline rates that became more predictable on a large group of base wells as this population of wells had been producing for more than two years.
Drilling asset impairment.
Impairment in 2017 reflects the write-down of remaining drilling and oilfield services assets classified as held for sale to net realizable value. Impairments were also recorded on certain drilling assets during the Predecessor 2016 Period, upon determining their future use was limited after discontinuing all remaining drilling operations in 2016.
Electrical infrastructure asset impairment.
Impairment in the Predecessor 2016 Period primarily reflects a write-down of the value of our electrical transmission system due to a decrease in projected Mid-Continent production volumes supporting the system’s usage.
Midstream asset impairment.
Impairment recorded on midstream assets in 2018 primarily reflects the write-down of midstream generator assets classified as held for sale to estimated net realizable value. Impairment recorded on midstream assets in 2016 resulted primarily from the write-down of generators, compressors and various other equipment due to their limited use.
General and administrative expenses decreased $34.4 million, or 45.2%, for the year ended December 31, 2018 compared to 2017 due primarily to (i) a decrease of $26.4 million in compensation related costs largely resulting from a reduction in force during the first quarter of 2018 as well as additional declines in headcount throughout 2018, (ii) a decrease of $6.0 million in professional services costs due primarily to incurring significant consultant fees in the 2017 period after our restructuring, and (iii) a net decrease of $2.0 million in other miscellaneous general and administrative items.
General and administrative expenses decreased $49.9 million, or 39.6%, for the year ended December 31, 2017 compared to 2016 due primarily to (i) a decrease of $25.0 million in professional services costs due to incurring significant consultant and legal fees in the 2016 period in contemplation of our restructuring, and (ii) a $23.6 million decrease in net salary costs largely resulting from reductions in force during the first and fourth quarters of 2016. The remaining change is due to the net effect of significant reductions in director and officer insurance costs, bad debt expense, and costs largely related to the reduction in headcount during 2016, offset partially by increases in other miscellaneous general and administrative items.
Accelerated vesting of employment compensation costs incurred during the year ended December 31, 2018 include compensation costs recognized for the accelerated vesting of certain share and incentive-based awards granted to our employees and directors related to the change in the composition of the Board resulting from the 2018 annual meeting as discussed in "Note 18 - Proxy Contest" to the consolidated financial statements in Item 8 of this report.
Proxy contest costs for the year ended December 31, 2018 include legal, consulting and advisory fees incurred in the proxy contest which were initiated in response to shareholder actions in 2018. See "Note 18 - Proxy Contest" to the consolidated financial statements in Item 8 of this report for additional discussion of this matter.
Terminated merger costs include legal and professional costs incurred from the aborted proposed merger of SandRidge with Bonanza Creek, as well as certain costs incurred to address shareholder claims and fees paid to Bonanza Creek for termination of the proposed merger in December 2017.
Employee termination benefits for the year ended December 31, 2018, include cash and share-based severance costs incurred primarily as a result of (i) the reduction in force in the first quarter of 2018 and (ii) severance costs associated with the departure of our former CEO, James Bennett, former CFO, Julian Bott, and other senior officers.
Employee termination benefits for the year ended December 31, 2017, primarily include cash and share-based severance costs incurred upon the departure of our former Executive Vice President of Investor Relations and Strategy, Duane Grubert.
Employee termination benefits for the year ended December 31, 2016, include cash and share-based severance costs incurred primarily as a result of (i) reductions in force in the first and fourth quarters of 2016, (ii) severance costs associated with the departure of executive officers and other senior officers and (iii) discontinuing all remaining drilling and oilfield services operations and the majority of all midstream and marketing services operations in the first quarter of 2016.
See "Note 19 - Employee Termination Benefits" to the consolidated financial statements in Item 8 of this report for additional information.
We recorded net loss (gain) on commodity derivative contracts of $17.2 million and $(24.1) million for the years ended December 31, 2018, and 2017, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash payments (receipts) upon settlement of $35.3 million and $(7.3) million, respectively. Approximately $0.8 million of the payments made in 2018 relate to early settlements due to unwinding all outstanding oil derivative contracts in December 2018.
As previously noted, on November 14, 2017, we entered into an Agreement and Plan of Merger with Bonanza Creek. In contemplation of the proposed merger, which would have been partially financed with debt, we entered into several oil derivative contracts in November 2017. Approximately $8.0 million of the total 2018 loss reported above related to net cash payments upon settlement for these oil derivatives. Approximately $4.9 million in losses were included in the net gain reported above related to these oil derivatives for the year ended December 31, 2017.
We recorded losses on commodity derivative contracts of $25.7 million and $4.8 million for the Successor 2016 Period and the Predecessor 2016 Period, respectively, as reflected in the accompanying consolidated statements of operations included in Item 8 of this report, which include net cash receipts upon settlement of $7.7 million and $72.6 million, respectively. Approximately $17.9 million of the net cash receipts for the Predecessor 2016 Period related to early settlements of commodity derivative contracts in the second quarter of 2016, primarily in response to the Chapter 11 Petitions being filed.
Our derivative contracts are not designated as accounting hedges and, as a result, changes in the fair value of our commodity derivative contracts are recorded each quarter as a component of operating expenses. Internally, management views the settlement of commodity derivative contracts at contractual maturity as adjustments to the price received for oil and natural gas production to determine “effective prices.” In general, cash is received on settlement of contracts due to lower oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts, and cash is paid on settlement of contracts due to higher oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts. See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” of this report for additional discussion of our commodity derivatives.
Loss on settlement of contract in the Predecessor 2016 Period consists of a $78.9 million loss resulting from the termination of a gas treating and CO
2
delivery agreement with Occidental, and a loss of $11.2 million recorded for the cease-use of transportation agreements that supported production from the Piñon field.
Other Income (Expense)
Other income (expense) for the years ended December 31, 2018 and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined year ended December 31, 2016, is reflected in the table below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
Predecessor
|
|
Combined
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
2016
|
|
2016
|
Other (expense) income
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
$
|
(2,787)
|
|
$
|
(3,868)
|
|
$
|
(372)
|
|
(126,099)
|
|
$
|
(126,471)
|
Gain on extinguishment of debt
|
1,151
|
|
—
|
|
—
|
|
41,179
|
|
41,179
|
Gain on reorganization items, net
|
—
|
|
—
|
|
—
|
|
2,430,599
|
|
2,430,599
|
Other income, net
|
2,865
|
|
2,550
|
|
2,744
|
|
1,332
|
|
4,076
|
Total other income (expense)
|
$
|
1,229
|
|
(1,318)
|
|
$
|
2,372
|
|
$
|
2,347,011
|
|
$
|
2,349,383
|
Interest expense for the years ended December 31, 2018 and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined year ended December 31, 2016 consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
Predecessor
|
|
Combined
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
2016
|
|
2016
|
Interest expense
|
|
|
|
|
|
|
|
|
|
Interest expense on debt
|
$
|
2,747
|
|
$
|
4,786
|
|
$
|
1,590
|
|
$
|
123,350
|
|
$
|
124,940
|
Amortization of debt issuance costs, premium and discounts
|
423
|
|
100
|
|
(81)
|
|
7,730
|
|
7,649
|
|
|
|
|
|
|
|
|
|
|
Gain on long-term debt derivatives
|
—
|
|
—
|
|
—
|
|
(1,324)
|
|
(1,324)
|
Capitalized interest
|
(22)
|
|
—
|
|
—
|
|
(2,240)
|
|
(2,240)
|
Total
|
3,148
|
|
4,886
|
|
1,509
|
|
127,516
|
|
129,025
|
Less: interest income
|
(361)
|
|
(1,018)
|
|
(1,137)
|
|
(1,417)
|
|
(2,554)
|
Total interest expense, net
|
$
|
2,787
|
|
$
|
3,868
|
|
$
|
372
|
|
$
|
126,099
|
|
$
|
126,471
|
Interest expense incurred during the years ended December 31, 2018 and 2017, is primarily comprised of interest recorded on the Building Note and commitment fees on the undrawn portion of the credit facility. Interest expense in the Successor 2016 Period is comprised of interest expense incurred on the First Lien Exit Facility prior to the payment of the outstanding balance in October 2016 and commitment fees on the undrawn portion of the First Lien Exit Facility and letters of credit. During the Predecessor 2016 Period, we recorded interest expense on our Senior Secured Notes, Senior Unsecured Notes, and senior credit facility prior to the Chapter 11 filings, and recorded fees on our letters of credit, and interest expense and commitment fees on our senior credit facility after the Chapter 11 filings through the emergence date.
Gain on extinguishment of debt was recognized for the year ended December 31, 2018 as a result of writing off the unamortized premium in conjunction with the repayment of the Building Note during the first quarter of 2018.
We recognized a gain on extinguishment of debt of $41.2 million in the Predecessor 2016 Period, primarily in connection with the exchange of $232.1 million in aggregate principal amount ($77.8 million net of discount and including holders’ conversion feature liabilities) of the Convertible Senior Unsecured Notes for approximately 84.4 million shares of the Predecessor Company’s common stock during the first quarter of 2016. Further conversions of the Convertible Senior Unsecured Notes were stayed in May 2016 in conjunction with the filing of the Chapter 11 petitions.
See “Note 10 - Long-Term Debt” to the consolidated financial statements in Item 8 of this report for additional discussion of our long-term debt transactions.
Reorganization items in the Predecessor 2016 Period primarily consist of the net gain recorded on the cancellation of Predecessor Company debt upon emergence from Chapter 11. See “Note 2 - Summary of Significant Accounting Policies” to the consolidated financial statements included in Item 8 of this Report for further discussion of reorganization items.
During the year ended December 31, 2017, we reduced the valuation allowance associated with our deferred tax assets related to alternative minimum tax credits that became realizable as a result of a special tax election. Accordingly, we recorded an income tax benefit of $8.7 million in the year ended December 31, 2017. Tax expense and the effective tax rate for the Successor 2016 Period and the Predecessor 2016 Period were low as a result of the valuation allowance against our net deferred tax asset in each period.
Liquidity and Capital Resources
At December 31, 2018, our cash and cash equivalents, excluding restricted cash, were $17.7 million. Additionally, we had no debt outstanding under our $350.0 million credit facility and $5.2 million in outstanding letters of credit, which reduce the amount available under the credit facility. As of February 20, 2019, the Company had approximately $10.9 million in cash and cash equivalents, excluding restricted cash, an undrawn credit facility, and $5.2 million in outstanding letters of credit.
Working Capital and Sources and Uses of Cash
Our principal sources of liquidity for 2019 include cash flow from operations, cash on hand and amounts available under our credit facility, as discussed in “—Credit Facility” below.
Our working capital deficit increased to $63.9 million at December 31, 2018, compared to $3.8 million at December 31, 2017, largely due to the repayment of the Building Note in the first quarter of 2018, employee termination benefits paid during the first quarter of 2018, cash paid on settlements of commodity derivative contracts and the acquisition of interests in certain Mid-Continent properties. This increase is partially offset by fluctuations in the timing and amount of collections of receivables and payments of accounts payable and accrued expenses, asset retirement obligation valuation adjustments related primarily to changes in estimated well lives, changes in derivative assets and liabilities due to quarterly mark-to-market adjustments, and proceeds received from the Permian Divestiture.
We intend to spend between $160.0 million and $180.0 million in our 2019 capital budget plan, with the majority of those expenditures being allocated to drilling and completion activities. We intend to fund capital expenditures and other commitments for the next 12 months using cash flow from our operations, borrowings under our credit facility and cash on hand. We will endeavor to keep our capital spending within or very close to our projected cash flows from operations subject to changing industry conditions or events.
Cash Flows
Our cash flows from operations are substantially dependent on current and future prices for oil and natural gas, which historically have been, and may continue to be, volatile. For example, during the period from January 2014 through December 2018, the NYMEX settled price for oil fluctuated between a high of $107.26 per Bbl and a low of $26.21 per Bbl, and the month-end NYMEX settled price for gas fluctuated between a high of $5.56 per MMBtu and a low of $1.71 per MMBtu.
If oil or natural gas prices decline from current levels, they could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. This could result in full cost pool ceiling impairments. Further, if our future capital expenditures are limited or deferred, or we are unsuccessful in developing reserves and adding production through our capital program, the value of our oil and natural gas properties, financial condition and results of operations could be adversely affected.
Cash flows for the years ended December 31, 2018 and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined year ended December 31, 2016, are presented in the following table and discussed below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
Predecessor
|
|
Combined
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
2016
|
|
2016
|
Cash flows provided by (used in) operating activities
|
$
|
145,514
|
|
$
|
181,179
|
|
$
|
65,595
|
|
$
|
(112,077)
|
|
$
|
(46,482)
|
Cash flows used in investing activities
|
(183,453)
|
|
(245,724)
|
|
(39,835)
|
|
(167,690)
|
|
(207,525)
|
Cash flows (used in) provided by financing activities
|
(43,724)
|
|
(8,218)
|
|
(415,061)
|
|
407,551
|
|
(7,510)
|
Net (decrease) increase in cash and cash equivalents
|
$
|
(81,663)
|
|
$
|
(72,763)
|
|
$
|
(389,301)
|
|
$
|
127,784
|
|
$
|
(261,517)
|
Cash Flows from Operating Activities
The $35.7 million decrease in operating cash flows for the year ended December 31, 2018 compared to 2017, is primarily due to (i) cash paid for employee termination benefits, (ii) cash paid on settlement of derivative contracts in 2018
compared to receiving cash in 2017, and (iii) other changes in working capital, partially offset by lower general administrative costs.
The $227.7 million increase in operating cash flows for the year ended December 31, 2017 compared to 2016, is primarily due to (i) a reduction in cash paid for interest expense, (ii) a decrease in professional and other fees paid in connection with our restructuring in 2016, (iii) a reduction in payroll and other employee related general and administrative costs, (iv) a reduction in production expenses, and (v) the 2016 period including cash payments for the early conversion of notes and the settlement of contracts. These decreases in expenses were partially offset by reductions in cash received for the settlement of derivatives and lower revenues in 2017 compared to 2016.
See “—Consolidated Results of Operations” for further analysis of the changes in operating expenses.
Cash Flows from Investing Activities
We dedicate and expect to continue to dedicate a substantial portion of our capital expenditure program toward the exploration for and development of our oil and natural gas properties. These capital expenditures are necessary to offset inherent declines in production and proved reserves, which is typical in the capital-intensive oil and natural gas industry. During the year ended December 31, 2018, cash flows used in investing activities primarily consisted of capital expenditures for drilling and completion activities and cash paid for the acquisition of interests in certain Mid-Continent properties. These expenditures were partially offset by cash proceeds received for the Permian Divestiture and other non-core asset divestitures in 2018.
During the year ended December 31, 2017, cash flows used in investing activities consisted primarily of capital expenditures for our exploration and development operations and the acquisition of 13,000 net acres in Woodward County, Oklahoma for approximately $47.8 million in cash, which were partially offset by proceeds from the sale of various non-core oil and natural gas properties and certain drilling equipment previously classified as held for sale.
During the combined year ended December 31, 2016, cash flows used in investing activities consisted primarily of capital expenditures for our exploration and development operations.
Capital Expenditures.
Our capital expenditures, on an accrual basis, for the years ended December 31, 2018 and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined year ended December 31, 2016 are summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
Predecessor
|
|
Combined
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
2016
|
|
2016
|
Capital Expenditures (on an accrual basis)
|
|
|
|
|
|
|
|
|
|
Drilling and completion
|
$
|
158,695
|
|
$
|
194,388
|
|
$
|
26,445
|
|
$
|
153,863
|
|
$
|
180,308
|
Leasehold and geophysical
|
11,680
|
|
51,645
|
|
11,617
|
|
1,764
|
|
13,381
|
Other - operating
|
419
|
|
854
|
|
2,901
|
|
3,108
|
|
6,009
|
Other - corporate
|
392
|
|
1,358
|
|
83
|
|
2,672
|
|
2,755
|
Capital expenditures, excluding acquisitions
|
171,186
|
|
248,245
|
|
41,046
|
|
161,407
|
|
202,453
|
Acquisitions
|
24,764
|
|
48,312
|
|
—
|
|
1,328
|
|
1,328
|
Total
|
$
|
195,950
|
|
$
|
296,557
|
|
$
|
41,046
|
|
$
|
162,735
|
|
$
|
203,781
|
Capital expenditures, excluding acquisitions, for exploration and development activities decreased for the year ended December 31, 2018 compared to 2017, primarily resulting from our lower capital expenditures budget and planned reduction in drilling activity as well as reductions in drilling costs in 2018.
Capital expenditures, excluding acquisitions, for exploration and development activities increased for the year ended December 31, 2017 compared to 2016, primarily due to drilling longer laterals in the North Park Basin, which are more capital intensive.
Cash Flows from Financing Activities
Our financing activities used $43.7 million of cash for the year ended December 31, 2018, which consisted primarily of repaying the Building Note and cash paid for employee tax obligations in connection with the withholding of common shares upon vesting of employee share-based compensation awards.
Our financing activities used $8.2 million of cash for the year ended December 31, 2017, which consisted primarily of cash paid for employee tax obligations in connection with the withholding of common shares upon the vesting of employee share-based compensation awards and deferred financing costs incurred on the credit facility.
Cash used in financing activities for the year ended December 31, 2016, was insignificant, primarily due to the net effect of borrowings and repayments under the First Lien Exit Facility, as well as proceeds received from the Building Note, which were subsequently remitted to unsecured creditors on the Emergence Date in accordance with the Plan.
Indebtedness
Credit Facility
We had no debt outstanding under our credit facility at December 31, 2018. The borrowing base under the credit facility is $350.0 million, which was reduced from $425.0 million during the October 2018 borrowing base redetermination. The next semi-annual borrowing base redetermination is scheduled for April 1, 2019. The credit facility matures on March 31, 2020. The credit facility is secured by (i) first-priority mortgages on at least 95% of the PV-9 valuation of all proved reserves included in the Company's most recently delivered reserve report, (ii) a first-priority perfected pledge of substantially all of the capital stock owned by each credit party and equity interests in the Royalty Trusts that are owned by a credit party and (iii) a first-priority perfected security interest in substantially all the cash, cash equivalents, deposits, securities and other similar accounts, and other tangible and intangible assets of the credit parties (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing).
The credit facility requires us to maintain (i) a maximum consolidated total net leverage ratio, measured as of the end of any fiscal quarter, of no greater than 3.50 to 1.00 and (ii) a minimum consolidated interest coverage ratio, measured as of the end of any fiscal quarter, of no less than 2.25 to 1.00. These financial covenants are subject to customary cure rights. We were in compliance with all applicable financial covenants under the credit facility as of December 31, 2018.
The credit facility contains customary affirmative and negative covenants, including compliance with certain laws (including environmental laws, ERISA and anti-corruption laws), maintaining required insurance, delivering quarterly and annual financial statements, oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on incurring liens and indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants.
The credit facility includes events of default relating to customary matters, including, among other things: nonpayment of principal, interest or other amounts, violation of covenants, incorrectness of representations and warranties in any material respect, cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $25.0 million or more, bankruptcy, judgments involving a liability of $25.0 million or more that are not paid, and ERISA events. Many events of default are subject to customary notice and cure periods.
Building Note
On the Emergence Date, we entered into the Building Note, which had an initial principal amount of $35.0 million and was secured by first priority mortgages on our real estate in Oklahoma City, Oklahoma. We repaid the Building Note in full during February 2018. The Building Note was recorded at fair value ($36.6 million) upon implementation of fresh start accounting, and approximately $1.3 million in in-kind interest costs were added to the principal prior to interest becoming payable in cash after the refinancing of the First Lien Exit Facility. The Building Note was set to mature on October 2, 2021, and was prepayable in whole or in part without premium or penalty.
See “Note 10 - Long-Term Debt” to the accompanying consolidated financial statements included in Item 8 of this report for additional discussion of the Company’s debt.
Contractual Obligations and Off-Balance Sheet Arrangements
At December 31, 2018, our contractual obligations included third-party drilling rig agreements, asset retirement obligations, operating leases, and other individually insignificant obligations. Additionally, we have certain financial instruments representing potential commitments that were incurred in the normal course of business to support our operations, including standby letters of credit and surety bonds. The underlying liabilities insured by these instruments are reflected in our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds.
As of December 31, 2018, we had future contractual payment commitments under various agreements, which are summarized below. The third-party drilling rig and operating leases are not recorded in the accompanying consolidated balance sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
|
|
|
Total
|
|
Less than
1 year
|
|
1-3 years
|
|
3-5 years
|
|
More than
5 years
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third-party drilling rig agreements(1)
|
$
|
3,595
|
|
$
|
3,595
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
Asset retirement obligations(2)
|
60,064
|
|
25,393
|
|
4,703
|
|
1,235
|
|
28,733
|
Leases and other
|
4,833
|
|
1,635
|
|
1,798
|
|
650
|
|
750
|
Total
|
$
|
68,492
|
|
$
|
30,623
|
|
$
|
6,501
|
|
$
|
1,885
|
|
$
|
29,483
|
____________________
1.
Includes drilling contracts with third-party drilling rig operators at specified day or footage rates and termination fees associated with our hydraulic fracturing services agreements. All of our drilling rig contracts contain operator performance conditions that allow for pricing adjustments or early termination for operator nonperformance.
2.
Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 201
8. Certain of these estimates and assumptions are inherently unpredictable and will differ from actual results given the uncertainty regarding the timing of such expenditures. As a result, we do not expect to incur all of the estimated costs for the current asset retirement obligation shown above in the next year, and have budgeted $4.5 million for actual expected plugging and abandonment costs in 2019.
Valuation Allowance
Upon emergence from bankruptcy and the application of fresh start accounting, our tax basis in property, plant, and equipment exceeded the book carrying value of our assets. Additionally, we had significant U.S. federal net operating losses remaining after the attribute reduction caused by the restructuring transactions. As such, the Successor Company had significant deferred tax assets to consume upon emergence. We considered all available evidence and concluded that it was more likely than not that some or all of the deferred tax assets would not be realized and established a valuation allowance against our net deferred tax asset upon emergence and maintained the valuation allowance for the subsequent periods through September 30, 2018.
We continue to closely monitor all available evidence in considering whether to maintain a valuation allowance on our net deferred tax asset. Factors considered include, but are not limited to, the reversal periods of existing deferred tax liabilities and deferred tax assets, our historical earnings and the prospects of future earnings. For purposes of the valuation allowance analysis, “earnings” is defined as pre-tax earnings as adjusted for permanent tax adjustments.
In determining whether to maintain the valuation allowance at December 31, 2018, we concluded that the objectively verifiable negative evidence of the presumption of cumulative negative earnings upon emergence and actual cumulative negative earnings for the Successor Company period ending December 31, 2018, is difficult to overcome with any forms of positive evidence that may exist. Accordingly, we have not changed our judgment regarding the need for a full valuation allowance against our net deferred tax asset for the period ending December 31, 2018.
See “Note 20 - Income Taxes” to the accompanying consolidated financial statements for additional discussion of income tax related matters.
Critical Accounting Policies and Estimates
The discussion and analysis of the Company’s financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of the Company’s financial statements requires management to make assumptions and prepare estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Estimates are based on historical experience and various other assumptions believed to be reasonable; however, actual results may differ significantly. The Company’s critical accounting policies and additional information on significant estimates are discussed below. See “Note 2—Summary of Significant Accounting Policies” to the Company’s consolidated financial statements in Item 8 of this report for additional discussion of significant accounting policies.
Fresh Start Accounting.
Upon emergence from bankruptcy, the Company applied fresh start accounting to its financial statements because (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the plan of reorganization was less than the post-petition liabilities and allowed claims. Fresh start accounting was applied to the Company’s consolidated financial statements as of October 1, 2016. Under the principles of fresh start accounting, a new reporting entity was considered to have been created, and, as a result, the reorganization value of the Company was allocated to its individual assets, including property, plant and equipment, based on their estimated fair values. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the financial statements on or after October 1, 2016, are not comparable with the financial statements prior to that date.
Derivative Financial Instruments.
To manage risks related to fluctuations in prices attributable to its expected oil and natural gas production, the Company enters into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates and issue long-term debt that contains embedded derivatives.
The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, accounts for its commodity derivative contracts at fair value with changes in fair value reported currently in earnings. The Company’s earnings may fluctuate significantly as a result of changes in fair value. Derivative assets and liabilities are netted whenever a legally enforceable master netting agreement exists with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows.
Fair values of the substantial majority of the Company’s commodity derivative financial instruments are determined primarily by using discounted cash flow calculations or option pricing models, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be corroborated from active markets. Estimates of future prices are based upon published forward commodity price curves for oil and natural gas instruments. Valuations also incorporate adjustments for the nonperformance risk of the Company or its counterparties, as applicable.
Proved Reserves.
Approximately 95.1% of the Company’s reserves were estimated by independent petroleum engineers for the year ended December 31, 2018. Estimates of proved reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Company’s control. Estimating reserves is a complex process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data. The accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues to change. For the years ended December 31, 2018, 2017 and 2016, the Company revised its proved reserves from prior years’
reports by approximately (33.2) MMBoe, 10.9 MMBoe and (105.4) MMBoe, respectively, due to production performance indicating more (or less) reserves in place, market prices during or at the end of the applicable period, larger (or smaller) reservoir size than initially estimated or additional proved reserve bookings within the original field boundaries. Estimates of proved reserves are key components of the Company’s financial estimates used to determine depreciation and depletion on oil and natural gas properties and its full cost ceiling limitation. Future revisions to estimates of proved reserves may be material and could materially affect the Company’s future depreciation, depletion and impairment expenses.
Method of Accounting for Oil and Natural Gas Properties.
The Company’s business is subject to accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full cost method. The Company uses the full cost method to account for its oil and natural gas properties. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Exploration and development costs include dry well costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil, natural gas and NGL reserves. Amortization of oil and natural gas properties is calculated using the unit-of-production method based on estimated proved oil, natural gas and NGL reserves. Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center.
Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion and impairment of oil and natural gas properties are generally calculated on a well by well, lease or field basis versus the aggregated “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of oil and natural gas properties under the successful efforts method. As a result, the Company’s financial statements will differ from companies that apply the successful efforts method since the Company will generally reflect a higher level of capitalized costs as well as a higher oil and natural gas depreciation and depletion rate, and the Company will not have exploration expenses that successful efforts companies frequently have.
Impairment of Oil and Natural Gas Properties.
In accordance with full cost accounting rules, capitalized costs are subject to a limitation. The capitalized cost of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes, may not exceed an amount equal to the ceiling limitation. The Company calculates its full cost ceiling limitation using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. If capitalized costs exceed the ceiling limitation, the excess must be charged to expense. Once incurred, a write-down cannot be reversed at a later date. The Successor Company recorded full cost ceiling impairment of $319.1 million for the period from October 2, 2016 through December 31, 2016, and the Predecessor Company recorded full cost ceiling impairments of $657.4 million for the period from January 1, 2016 through October 1, 2016. No full cost ceiling impairment was recorded for the years ended December 31, 2018 and 2017. See “—Consolidated Results of Operations” for additional discussion of full cost ceiling impairments.
Unproved Properties.
The balance of unproved properties consists primarily of costs to acquire unproved acreage. These costs are initially excluded from the Company’s amortization base until it is known whether proved reserves will or will not be assigned to the property. The Company assesses all properties, on an individual basis or as a group if properties are individually insignificant, classified as unproved on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. For leases that do not have existing production that would otherwise extend the lease term, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a three to five year period from the original lease date. For leases that are held by production, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a 10-year period from the original lease date.
Property, Plant and Equipment, Net.
Other capitalized costs including other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost or the fair value established on the Emergence Date. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 7 to 39 years for
buildings and 1 to 27 years for the electrical infrastructure assets and other equipment. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in operations. The carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset or asset group may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. If an asset or asset group is determined to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset or asset group exceeds its fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. The Company may also determine fair value by using the present value of estimated future cash inflows and/or outflows, or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Changes in such estimates could cause the Company to reduce the carrying value of property and equipment.
See “—Consolidated Results of Operations” and “Note 8—Impairment” to the Company’s consolidated financial statements in Item 8 of this report for a discussion of the Company’s impairments.
Asset Retirement Obligations.
Asset retirement obligations represent the estimate of fair value of the cost to plug, abandon and remediate the Company’s wells at the end of their productive lives, in accordance with applicable federal and state laws. The Company estimates the fair value of an asset’s retirement obligation in the period in which the liability is incurred (at the time the wells are drilled or acquired). Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. The Company employs a present value technique to estimate the fair value of an asset retirement obligation, which reflects certain assumptions and requires significant judgment, including an inflation rate, its credit-adjusted, risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability based on third-party quotes and current actual costs. Inherent in the present value calculation are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.
Revenue Recognition.
Sales of oil, natural gas and NGLs are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck, net of royalties, discounts and allowances, as applicable. The Successor Company deducts transportation costs from oil, natural gas and NGL revenues. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are included in production tax expense in the consolidated statements of operations. See "Note 17—Revenues" to the Company's consolidated financial statements in Item 8 of this report for further information on the Company's accounting policies related to revenues.
Income Taxes.
Deferred income taxes are recorded for temporary differences between the financial statement and income tax basis of assets and liabilities. Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns. As of December 31, 2018, the Company had a full valuation allowance against its net deferred tax asset. The valuation allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence.
New Accounting Pronouncements.
For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 2—Summary of Significant Accounting Policies” to the Company’s consolidated financial statements in Item 8 of this report.
Item 8.
Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Management’s Report on Internal Control over Financial Reporting
Management of SandRidge Energy, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018. In making this assessment, management used the criteria established in
Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013) (the COSO criteria). Based on management’s assessment using the COSO criteria, management concluded the Company’s internal control over financial reporting was effective as of December 31, 2018.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2018 has been audited by PricewaterhouseCoopers LLP an independent registered public accounting firm, as stated in its report which appears herein.
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|
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|
|
/s/ P
AUL
D. M
C
K
INNEY
|
|
/s/ M
ICHAEL
A
.
J
OHNSON
|
Paul D. McKinney
President and Chief Executive Officer
|
|
Michael A. Johnson
Senior Vice President and Chief Financial Officer
|
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of SandRidge Energy, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have
audited the accompanying consolidated balance sheets of SandRidge Energy, Inc. and its subsidiaries (Successor) (the "Company")
as of December 31, 2018
and 2017,
and the related consolidated statements of operations, changes in stockholders’ equity (deficit) and cash flows
for the years then ended and for the period from October 2, 2016 through December 31, 2016, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in
Internal Control - Integrated Framework
(2013)
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated
financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017
,
and the results of its
operations and its cash flows for the years then ended and for the period from October 2, 2016 through 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, 2018, based on criteria established in
Internal Control - Integrated Framework
(2013)
issued by the COSO.
Basis of Accounting
As discussed in Note 1 to the consolidated
financial statements, the United States Bankruptcy Court for the district of Southern Texas confirmed the Company's Amended Joint Chapter 11 Plan of Reorganization (the "plan") on September 9, 2016. Confirmation of the plan resulted in the discharge of all claims against the Company that arose before October 1, 2016
and substantially alters or terminates all rights and interests of equity security holders as provided for in the plan. The plan was substantially consummated on October 4, 2016
and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the
Company adopted fresh start accounting as of October 1, 2016.
Basis for Opinions
The Company's management is responsible for these consolidated 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 the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated
financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated
financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated
financial statements included performing procedures to assess the risks of material misstatement of the consolidated
financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated
financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated
financial statements. 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.
Definition and Limitations of Internal Control over Financial Reporting
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.
|
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/s/ PricewaterhouseCoopers LLP
|
|
PricewaterhouseCoopers LLP
|
|
Oklahoma City, Oklahoma
|
|
March 5, 2019
|
|
|
|
We have served as the Company’s auditor since 2005.
|
|
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of SandRidge Energy, Inc.
In our opinion, the accompanying consolidated statements of operations, changes in stockholders’ equity (deficit) and cash flows present fairly, in all material respects, the results of operations and cash flows of SandRidge Energy, Inc. and its subsidiaries (Predecessor) (the "Company") for the period from January 1, 2016 to October 1, 2016 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company filed a petition on May 16, 2016 with the United States Bankruptcy Court for the district of Southern Texas for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company’s Amended Joint Chapter 11 Plan of Reorganization
was substantially consummated on October 4, 2016
and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the
Company adopted fresh start accounting.
|
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|
|
/s/ PricewaterhouseCoopers LLP
|
|
PricewaterhouseCoopers LLP
|
|
Oklahoma City, Oklahoma
|
|
March 3, 2017
|
|
SandRidge Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
December 31,
|
|
2018
|
|
2017
|
ASSETS
|
|
|
|
Current assets
|
|
|
|
Cash and cash equivalents
|
$
|
17,660
|
|
$
|
99,143
|
|
|
|
|
Restricted cash - other
|
1,985
|
|
2,165
|
Accounts receivable, net
|
45,503
|
|
71,277
|
Derivative contracts
|
5,286
|
|
1,310
|
Prepaid expenses
|
2,628
|
|
5,248
|
Other current assets
|
265
|
|
15,954
|
Total current assets
|
73,327
|
|
195,097
|
Oil and natural gas properties, using full cost method of accounting
|
|
|
|
Proved
|
1,269,091
|
|
1,056,806
|
Unproved
|
60,152
|
|
100,884
|
Less: accumulated depreciation, depletion and impairment
|
(580,132)
|
|
(460,431)
|
|
749,111
|
|
697,259
|
Other property, plant and equipment, net
|
200,838
|
|
225,981
|
Other assets
|
1,062
|
|
1,290
|
Total assets
|
$
|
1,024,338
|
|
$
|
1,119,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
Current liabilities
|
|
|
|
Accounts payable and accrued expenses
|
$
|
111,797
|
|
$
|
139,155
|
Derivative contracts
|
—
|
|
10,627
|
Asset retirement obligations
|
25,393
|
|
41,017
|
Other current liabilities
|
—
|
|
8,115
|
Total current liabilities
|
137,190
|
|
198,914
|
Long-term debt
|
—
|
|
37,502
|
Derivative contracts
|
—
|
|
3,568
|
Asset retirement obligations
|
34,671
|
|
36,527
|
Other long-term obligations
|
4,756
|
|
3,176
|
Total liabilities
|
176,617
|
|
279,687
|
Commitments and contingencies (Note 13)
|
|
|
|
Stockholders’ Equity
|
|
|
|
Common stock, $0.001 par value; 250,000 shares authorized; 35,687 issued and outstanding at December 31, 2018 and 35,650 issued and outstanding at December 31, 2017
|
36
|
|
36
|
Warrants
|
88,516
|
|
88,500
|
Additional paid-in capital
|
1,055,164
|
|
1,038,324
|
Accumulated deficit
|
(295,995)
|
|
(286,920)
|
Total stockholders’ equity
|
847,721
|
|
839,940
|
Total liabilities and stockholders’ equity
|
$
|
1,024,338
|
|
$
|
1,119,627
|
The accompanying notes are an integral part of these consolidated financial statements.
SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
For the Years Ended December 31, 2018 and 2017, the Period from October 2, 2016 through December 31, 2016 and the Period from January 1, 2016 through October 1, 2016
(In thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
Revenues
|
|
|
|
|
|
|
|
|
Oil, natural gas and NGL
|
$
|
348,726
|
|
$
|
356,210
|
|
$
|
98,307
|
|
|
$
|
279,971
|
Other
|
669
|
|
1,089
|
|
149
|
|
|
13,838
|
Total revenues
|
349,395
|
|
357,299
|
|
98,456
|
|
|
293,809
|
Expenses
|
|
|
|
|
|
|
|
|
Production
|
92,703
|
|
102,728
|
|
24,997
|
|
|
129,608
|
Production taxes
|
19,470
|
|
13,644
|
|
2,643
|
|
|
6,107
|
Depreciation and depletion—oil and natural gas
|
127,281
|
|
118,035
|
|
36,061
|
|
|
90,978
|
Depreciation and amortization—other
|
11,982
|
|
13,852
|
|
3,922
|
|
|
21,323
|
Impairment
|
4,170
|
|
4,019
|
|
319,087
|
|
|
718,194
|
General and administrative
|
41,666
|
|
76,024
|
|
9,837
|
|
|
116,091
|
Accelerated vesting of employment compensation
|
6,545
|
|
—
|
|
—
|
|
|
—
|
Proxy contest
|
7,139
|
|
—
|
|
—
|
|
|
—
|
Terminated merger costs
|
—
|
|
8,162
|
|
—
|
|
|
—
|
Employee termination benefits
|
32,657
|
|
4,815
|
|
12,334
|
|
|
18,356
|
Loss (gain) on derivative contracts
|
17,155
|
|
(24,090)
|
|
25,652
|
|
|
4,823
|
Loss on settlement of contract
|
—
|
|
—
|
|
—
|
|
|
90,184
|
Other operating (income) expense
|
(998)
|
|
479
|
|
268
|
|
|
4,348
|
Total expenses
|
359,770
|
|
317,668
|
|
434,801
|
|
|
1,200,012
|
(Loss) income from operations
|
(10,375)
|
|
39,631
|
|
(336,345)
|
|
|
(906,203)
|
Other (expense) income
|
|
|
|
|
|
|
|
|
Interest expense
|
(2,787)
|
|
(3,868)
|
|
(372)
|
|
|
(126,099)
|
Gain on extinguishment of debt
|
1,151
|
|
—
|
|
—
|
|
|
41,179
|
Gain on reorganization items, net
|
—
|
|
—
|
|
—
|
|
|
2,430,599
|
Other income, net
|
2,865
|
|
2,550
|
|
2,744
|
|
|
1,332
|
Total other income (expense)
|
1,229
|
|
(1,318)
|
|
2,372
|
|
|
2,347,011
|
(Loss) income before income taxes
|
(9,146)
|
|
38,313
|
|
(333,973)
|
|
|
1,440,808
|
Income tax (benefit) expense
|
(71)
|
|
(8,749)
|
|
9
|
|
|
11
|
Net (loss) income
|
(9,075)
|
|
47,062
|
|
(333,982)
|
|
|
1,440,797
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividends
|
—
|
|
—
|
|
—
|
|
|
16,321
|
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders
|
$
|
(9,075)
|
|
$
|
47,062
|
|
$
|
(333,982)
|
|
|
$
|
1,424,476
|
(Loss) earnings per share
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.26)
|
|
$
|
1.45
|
|
$
|
(17.61)
|
|
|
$
|
2.01
|
Diluted
|
$
|
(0.26)
|
|
$
|
1.44
|
|
$
|
(17.61)
|
|
|
$
|
2.01
|
Weighted average number of common shares outstanding
|
|
|
|
|
|
|
|
|
Basic
|
35,057
|
|
32,442
|
|
18,967
|
|
|
708,928
|
Diluted
|
35,057
|
|
32,663
|
|
18,967
|
|
|
708,928
|
The accompanying notes are an integral part of these consolidated financial statements.
SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)
For the Years Ended December 31, 2018 and 2017, the Period from October 2, 2016 through December 31, 2016 and the Period from January 1, 2016 through October 1, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible
Perpetual
Preferred Stock
|
|
|
|
Common Stock
|
|
|
|
Additional
Paid-In
Capital
|
|
Treasury
Stock
|
|
Accumulated
Deficit
|
|
Non-controlling
Interest
|
|
Total
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2015 - Predecessor
|
5,420
|
|
$
|
6
|
|
633,471
|
|
$
|
630
|
|
$
|
5,299,886
|
|
$
|
(5,742)
|
|
$
|
(6,992,697)
|
|
$
|
510,184
|
|
$
|
(1,187,733)
|
Cumulative effect of adoption of ASU 2015-02
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
257,081
|
|
(510,205)
|
|
(253,124)
|
Cash paid for tax withholdings on vested stock awards
|
—
|
|
—
|
|
—
|
|
—
|
|
(44)
|
|
—
|
|
—
|
|
—
|
|
(44)
|
Stock distributions, net of purchases - retirement plans
|
—
|
|
—
|
|
603
|
|
—
|
|
(860)
|
|
524
|
|
—
|
|
—
|
|
(336)
|
Stock-based compensation
|
—
|
|
—
|
|
—
|
|
—
|
|
11,102
|
|
—
|
|
—
|
|
—
|
|
11,102
|
Cancellations of restricted stock awards, net of issuance
|
—
|
|
—
|
|
(2,184)
|
|
2
|
|
(2)
|
|
—
|
|
—
|
|
—
|
|
—
|
Common stock issued for debt
|
—
|
|
—
|
|
84,390
|
|
84
|
|
4,325
|
|
—
|
|
—
|
|
—
|
|
4,409
|
Conversion of preferred stock to common stock
|
(173)
|
|
—
|
|
2,220
|
|
2
|
|
(2)
|
|
—
|
|
—
|
|
—
|
|
—
|
Net income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1,440,797
|
|
—
|
|
1,440,797
|
Convertible perpetual preferred stock dividends
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(16,321)
|
|
—
|
|
(16,321)
|
Balance at October 1, 2016 - Predecessor
|
5,247
|
|
6
|
|
718,500
|
|
718
|
|
5,314,405
|
|
(5,218)
|
|
(5,311,140)
|
|
(21)
|
|
(1,250)
|
Cancellation of Predecessor equity
|
(5,247)
|
|
(6)
|
|
(718,500)
|
|
(718)
|
|
(5,314,405)
|
|
5,218
|
|
5,311,140
|
|
21
|
|
1,250
|
Balance at October 1, 2016 - Predecessor
|
—
|
|
$
|
—
|
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
The accompanying notes are an integral part of these consolidated financial statements.
SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)—Continued
For the Years Ended December 31, 2018 and 2017, the Period from October 2, 2016 through December 31, 2016 and the Period from January 1, 2016 through October 1, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
|
Warrants
|
|
|
|
Additional
Paid-In
Capital
|
|
Accumulated
Deficit
|
|
Total
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at October 1, 2016 - Predecessor
|
—
|
|
$
|
—
|
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
Issuance of Successor common stock
|
18,932
|
|
19
|
|
—
|
|
—
|
|
575,144
|
|
—
|
|
575,163
|
Issuance of Successor warrants
|
—
|
|
—
|
|
6,442
|
|
88,382
|
|
—
|
|
—
|
|
88,382
|
Convertible note premium
|
—
|
|
—
|
|
—
|
|
—
|
|
163,879
|
|
—
|
|
163,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at October 1, 2016 - Successor
|
18,932
|
|
19
|
|
6,442
|
|
88,382
|
|
739,023
|
|
—
|
|
827,424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of stock awards, net of cancellations
|
10
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
Common stock issued for debt
|
693
|
|
1
|
|
—
|
|
—
|
|
13,000
|
|
—
|
|
13,001
|
Common stock issued for warrants
|
—
|
|
—
|
|
—
|
|
(1)
|
|
4
|
|
—
|
|
3
|
Stock-based compensation
|
—
|
|
—
|
|
—
|
|
—
|
|
6,581
|
|
—
|
|
6,581
|
Cash paid for tax withholdings on vested stock awards
|
—
|
|
—
|
|
—
|
|
—
|
|
(110)
|
|
—
|
|
(110)
|
Net loss
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(333,982)
|
|
(333,982)
|
Balance at December 31, 2016 - Successor
|
19,635
|
|
20
|
|
6,442
|
|
88,381
|
|
758,498
|
|
(333,982)
|
|
512,917
|
Issuance of stock awards, net of cancellations
|
1,583
|
|
2
|
|
—
|
|
—
|
|
(2)
|
|
—
|
|
—
|
Common stock issued for debt
|
14,328
|
|
14
|
|
—
|
|
—
|
|
268,765
|
|
—
|
|
268,779
|
Common stock issued for general unsecured claims
|
104
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
Stock-based compensation
|
—
|
|
—
|
|
—
|
|
—
|
|
17,912
|
|
—
|
|
17,912
|
Issuance of warrants for general unsecured claims
|
—
|
|
—
|
|
128
|
|
119
|
|
(119)
|
|
—
|
|
—
|
Cash paid for tax withholdings on vested stock awards
|
—
|
|
—
|
|
—
|
|
—
|
|
(6,730)
|
|
—
|
|
(6,730)
|
Net income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
47,062
|
|
47,062
|
Balance at December 31, 2017 - Successor
|
35,650
|
|
36
|
|
6,570
|
|
88,500
|
|
1,038,324
|
|
(286,920)
|
|
839,940
|
Issuance of stock awards, net of cancellations
|
9
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued for general unsecured claims
|
28
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
Stock-based compensation
|
—
|
|
—
|
|
—
|
|
—
|
|
24,276
|
|
—
|
|
24,276
|
Issuance of warrants for general unsecured claims
|
—
|
|
—
|
|
34
|
|
16
|
|
(16)
|
|
—
|
|
—
|
Cash paid for tax withholdings on vested stock awards
|
—
|
|
—
|
|
—
|
|
—
|
|
(7,420)
|
|
—
|
|
(7,420)
|
Net loss
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(9,075)
|
|
(9,075)
|
Balance at December 31, 2018 - Successor
|
35,687
|
|
$
|
36
|
|
6,604
|
|
$
|
88,516
|
|
$
|
1,055,164
|
|
$
|
(295,995)
|
|
$
|
847,721
|
The accompanying notes are an integral part of these consolidated financial statements.
SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2018 and 2017, the Period from October 2, 2016 through December 31, 2016 and the Period from January 1, 2016 through October 1, 2016
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
Net (loss) income
|
$
|
(9,075)
|
|
$
|
47,062
|
|
$
|
(333,982)
|
|
|
$
|
1,440,797
|
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities
|
|
|
|
|
|
|
|
|
Provision for doubtful accounts
|
(462)
|
|
406
|
|
(13,166)
|
|
|
16,704
|
Depreciation, depletion and amortization
|
139,263
|
|
131,887
|
|
39,983
|
|
|
112,301
|
Impairment
|
4,170
|
|
4,019
|
|
319,087
|
|
|
718,194
|
Gain on reorganization items, net
|
—
|
|
—
|
|
—
|
|
|
(2,442,436)
|
Debt issuance costs amortization
|
470
|
|
430
|
|
—
|
|
|
4,996
|
Amortization of discount, net of premium, on debt
|
(47)
|
|
(330)
|
|
(81)
|
|
|
2,734
|
Gain on extinguishment of debt
|
(1,151)
|
|
—
|
|
—
|
|
|
(41,179)
|
|
|
|
|
|
|
|
|
|
Gain on debt derivatives
|
—
|
|
—
|
|
—
|
|
|
(1,324)
|
Cash paid for early conversion of convertible notes
|
—
|
|
—
|
|
—
|
|
|
(33,452)
|
|
|
|
|
|
|
|
|
|
Loss (gain) on derivative contracts
|
17,155
|
|
(24,090)
|
|
25,652
|
|
|
4,823
|
Cash (paid) received on settlement of derivative contracts
|
(35,325)
|
|
7,260
|
|
7,698
|
|
|
72,608
|
Loss on settlement of contract
|
—
|
|
—
|
|
—
|
|
|
90,184
|
Cash paid on settlement of contract
|
—
|
|
—
|
|
—
|
|
|
(11,000)
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
23,377
|
|
15,750
|
|
6,250
|
|
|
9,075
|
Other
|
(1,571)
|
|
344
|
|
717
|
|
|
(3,260)
|
Changes in operating assets and liabilities increasing (decreasing) cash
|
|
|
|
|
|
|
|
|
Deconsolidation of noncontrolling interest
|
—
|
|
—
|
|
—
|
|
|
(9,654)
|
Receivables
|
16,560
|
|
115
|
|
12,872
|
|
|
36,116
|
Prepaid expenses
|
2,620
|
|
127
|
|
(1,079)
|
|
|
(5,681)
|
Other current assets
|
170
|
|
191
|
|
(260)
|
|
|
(181)
|
Other assets and liabilities, net
|
(1,754)
|
|
4,186
|
|
1,505
|
|
|
(7,542)
|
Accounts payable and accrued expenses
|
(4,257)
|
|
(2,199)
|
|
990
|
|
|
(3,595)
|
Asset retirement obligations
|
(4,629)
|
|
(3,979)
|
|
(591)
|
|
|
(61,305)
|
Net cash provided by (used in) operating activities
|
145,514
|
|
181,179
|
|
65,595
|
|
|
(112,077)
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital expenditures for property, plant and equipment
|
(187,047)
|
|
(219,246)
|
|
(51,676)
|
|
|
(186,452)
|
Acquisitions of assets
|
(24,764)
|
|
(48,312)
|
|
—
|
|
|
(1,328)
|
Proceeds from sale of assets
|
28,358
|
|
21,834
|
|
11,841
|
|
|
20,090
|
Net cash used in investing activities
|
(183,453)
|
|
(245,724)
|
|
(39,835)
|
|
|
(167,690)
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
Proceeds from borrowings
|
10,000
|
|
—
|
|
—
|
|
|
489,198
|
Repayments of borrowings
|
(46,304)
|
|
—
|
|
(414,954)
|
|
|
(74,243)
|
Debt issuance costs
|
—
|
|
(1,488)
|
|
—
|
|
|
(333)
|
Proceeds from building mortgage
|
—
|
|
—
|
|
—
|
|
|
26,847
|
Payment of mortgage proceeds and cash recovery to debt holders
|
—
|
|
—
|
|
—
|
|
|
(33,874)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for tax withholdings on vested stock awards
|
(7,420)
|
|
(6,730)
|
|
(110)
|
|
|
(44)
|
|
|
|
|
|
|
|
|
|
Other
|
—
|
|
—
|
|
3
|
|
|
—
|
Net cash (used in) provided by financing activities
|
(43,724)
|
|
(8,218)
|
|
(415,061)
|
|
|
407,551
|
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH
|
(81,663)
|
|
(72,763)
|
|
(389,301)
|
|
|
127,784
|
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year
|
101,308
|
|
174,071
|
|
563,372
|
|
|
435,588
|
CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of year
|
$
|
19,645
|
|
$
|
101,308
|
|
$
|
174,071
|
|
|
$
|
563,372
|
The accompanying notes are an integral part of these consolidated financial statements.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
1. Voluntary Reorganization under Chapter 11 Proceedings
On May 16, 2016, the Debtors filed the Bankruptcy Petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan on September 9, 2016, and the Debtors’ subsequently emerged from bankruptcy on the Emergence Date. Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession through October 4, 2016. As such, the Company’s bankruptcy proceedings and related matters have been summarized below.
The Company was able to conduct normal business activities and pay associated obligations for the period following its bankruptcy filing and was authorized to pay and has paid certain pre-petition obligations, including employee wages and benefits, goods and services provided by certain vendors, transportation of the Company’s production, royalties and costs incurred on the Company’s behalf by other working interest owners. During the pendency of the Chapter 11 case, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.
Automatic Stay.
Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities were subject to settlement under the Bankruptcy Code.
Plan of Reorganization.
In accordance with the plan of reorganization confirmed by the Bankruptcy Court, the following significant transactions occurred upon the Company’s emergence from bankruptcy on October 4, 2016:
•
First Lien Credit Agreement.
All outstanding obligations under the senior credit facility were canceled, and claims under the senior credit facility received their proportionate share of (a) $35.0 million in cash and (b) participation in the newly established $425.0 million First Lien Exit Facility. Refer to Note 10 for additional information.
•
Cash Collateral Account.
The Company deposited $50.0 million of cash in a Cash Collateral Account. This deposit was released to the Company in February 2017 in conjunction with the refinancing of the First Lien Exit Facility.
•
Senior Secured Notes
. All outstanding obligations under the Senior Secured Notes were canceled and exchanged for approximately 13.7 million of the 18.9 million shares of Common Stock issued at emergence. Additionally, claims under the Senior Secured Notes received approximately $281.8 million principal amount of newly issued Convertible Notes, which mandatorily converted into 14.1 million shares of Common Stock upon the refinancing of the First Lien Exit Facility in February 2017. Refer to Note 10 for additional information.
•
General Unsecured Claims.
The Company’s general unsecured claims, including the Unsecured Notes, became entitled to receive their proportionate share of (a) approximately $36.7 million in cash, (b) approximately 5.7 million shares of Common Stock, 5.2 million of which was issued immediately upon emergence, and (c) 4.9 million Series A Warrants, 4.5 million issued immediately upon emergence, and 2.1 million Series B Warrants, 1.9 million issued immediately upon emergence. Refer to Note 14 for additional information.
•
Building Note
. The Building Note with a principal amount of $35.0 million ($36.6 million fair value on the Emergence Date), was issued and purchased on the Emergence Date for $26.8 million in cash, net of certain fees and expenses, by certain holders of the Senior Unsecured Notes. Proceeds received from the Building Note were subsequently remitted to unsecured creditors on the Emergence Date in accordance with the Plan. Refer to Note 10 for additional information.
•
Preferred and Common Stock.
The Company’s existing 7.0% and 8.5% convertible perpetual preferred stock and common stock were canceled and released under the Plan without receiving any recovery on account thereof.
2. Summary of Significant Accounting Policies
Fresh Start Accounting.
Upon emergence from bankruptcy, the Company applied fresh start accounting to its financial statements because (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the plan of reorganization was less than the post-petition liabilities and allowed claims.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The Company elected to apply fresh start accounting effective October 1, 2016, to coincide with the timing of its normal fourth quarter reporting period, which resulted in SandRidge becoming a new entity for financial reporting purposes. The Company evaluated and concluded that events between October 1, 2016, and October 4, 2016, were immaterial and use of an accounting convenience date of October 1, 2016, was appropriate. As such, related fresh start adjustments are included in the accompanying statement of operations for the Predecessor 2016 Period. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements for the Successor 2016 Period will not be comparable with the financial statements prior to that date.
Reorganization Value.
Reorganization value represented the fair value of the Successor Company’s total assets on the Emergence Date and approximated the amount a willing buyer would pay for the assets immediately after restructuring. Under fresh start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values.
The Company’s reorganization value was derived from an estimate of enterprise value, which represented the estimated fair value of long-term debt and other interest-bearing liabilities and shareholders’ equity. In support of the Plan, the Company estimated the enterprise value of the Successor Company to be in the range of $1.0 billion to $1.3 billion, which was subsequently approved by the Bankruptcy Court. The Company estimated the final enterprise value to be approximately $1.1 billion. This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections, third-party real estate reports, and applying standard valuation techniques, including net asset value analysis, precedent transactions analyses and public comparable company analyses.
The following table reconciles the enterprise value to the estimated reorganization value as of the Emergence Date (in thousands):
|
|
|
|
|
|
|
|
|
Enterprise value
|
|
$
|
1,089,808
|
Plus: cash and cash equivalents
|
|
563,372
|
Plus: other working capital liabilities
|
|
131,766
|
Plus: other long-term liabilities
|
|
8,549
|
Reorganization value of Successor assets
|
|
$
|
1,793,495
|
Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates included in this report are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Reorganization Items
Reorganization items represent liabilities settled, net of amounts incurred, subsequent to the Chapter 11 filing as a direct result of the Plan and are classified as gain on reorganization items, net in the accompanying consolidated statement of operations. The following table summarizes reorganization items for the Predecessor 2016 Period (in thousands):
|
|
|
|
|
|
|
|
|
Unamortized long-term debt
|
|
$
|
3,546,847
|
Litigation claims
|
|
(20,478)
|
Rejections and cures of executory contracts
|
|
(16,038)
|
Ad valorem and franchise taxes
|
|
(3,494)
|
Legal and professional fees and expenses
|
|
(44,920)
|
Write off of director and officer insurance policy
|
|
(7,533)
|
Gain on accounts payable settlements
|
|
84,228
|
Loss on mortgage
|
|
(8,153)
|
Gain on preferred stock dividends
|
|
37,893
|
Fresh start valuation adjustments
|
|
(28,549)
|
Fair value of equity issued
|
|
(827,424)
|
Principal value of Convertible Notes issued
|
|
(281,780)
|
Gain on reorganization items, net
|
|
$
|
2,430,599
|
Nature of Business.
SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on the acquisition, exploration and development of hydrocarbon resources in the United States.
Principles of Consolidation.
The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. The Company proportionately consolidates the activities of the Royalty Trusts.
Reclassifications.
Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations.
Use of Estimates.
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and NGL reserves; impairment tests of long-lived assets; the carrying value of unproved oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; determinations of significant alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to divested properties, as necessary; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly.
Cash and Cash Equivalents.
The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period.
Restricted Cash.
The Company
maintains restricted escrow funds as required by certain contractual arrangements in accordance with the Plan.
Accounts Receivable, Net.
The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the drilling, completion, and production of oil and natural gas, which have a contractual maturity of one year or less. An allowance for doubtful accounts has been established based on management’s review of the collectibility of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 6 for further information on the Company’s accounts receivable and allowance for doubtful accounts.
Fair Value of Financial Instruments.
Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, restricted cash, trade receivables, prepaid expenses, and trade payables and accrued expenses. The carrying values of cash, trade receivables and trade payables are considered to reflect fair values due to the short-term maturity of these instruments. See Note 5 for further discussion of the Company’s fair value measurements.
Fair Value of Non-financial Assets and Liabilities.
The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows, third-party offers or prices of comparable assets with consideration of current market conditions to fair value its non-financial assets and liabilities when necessary.
Derivative Financial Instruments.
The Company enters into oil and natural gas derivative contracts to manage risks related to fluctuations in prices of its expected oil and natural gas production. The Company considers current and anticipated market conditions, planned capital expenditures, and any debt service requirements when determining whether to enter into oil and gas derivative contracts. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates.
The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows. See Note 11 for further discussion of the Company’s derivatives.
Oil and Natural Gas Operations.
The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Successor Company capitalized gross internal costs of $8.8 million, $14.8 million and $4.0 million during the years ended December 31, 2018 and 2017, and the Successor 2016 Period, respectively, and the Predecessor Company capitalized internal costs of $22.7 million to the full cost pool during the Predecessor 2016 Period. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.
Costs associated with unproved properties are excluded from the amortizable cost base until it has been determined that proved reserves exist or a lease is impaired. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and amortized. The costs associated with unproved properties are primarily the costs to acquire unproved acreage. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and whether the proved reserves can be developed economically. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed the ceiling limitation. A ceiling limitation calculation is performed at the end of each quarter. If the ceiling limitation is exceeded, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date.
The ceiling limitation calculation is prepared using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. If applicable, these prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation.
Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center.
Property, Plant and Equipment, Net.
Other capitalized costs, including other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost or the fair value established on the Emergence Date. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 7 to 39 years for buildings and 1 to 27 years for the electrical infrastructure assets and other equipment. When property and equipment components are disposed, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations.
Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value is less than the carrying amount of the asset or asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value. See Note 8 for further discussion of impairments.
Capitalized Interest.
Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time. During the year ended December 31, 2018 the Company capitalized an insignificant amount of interest costs and in the year ended December 31, 2017, and the Successor 2016 Period, the Company did not capitalize any interest costs as capital expenditures were not financed with debt during these periods. During the Predecessor 2016 Period, the Company capitalized interest of approximately $2.2 million on unproved properties that were not currently being depreciated or depleted and on which exploration activities were in progress.
Debt Issuance Costs.
The Company includes unamortized line-of-credit debt issuance costs, if any, related to its credit facility in other assets in the consolidated balance sheets. Other debt issuance costs related to long-term debt, if any, are presented in the balance sheets as a direct deduction from the associated debt liability. Debt issuance costs are amortized to interest expense over the term of the related debt. When debt is retired, any unamortized costs are written off and included in gain or loss on extinguishment of debt.
Investments.
Investments in marketable equity securities at December 31, 2017 related to the Company’s then-outstanding non-qualified deferred compensation plan. The investments in this plan were designated as available for sale and measured at fair value using quoted prices readily available in the market (fair value option) which requires unrealized gains and losses be reported in earnings. Investments are included in other current assets and other assets in the accompanying consolidated balance sheet at December 31, 2017. The non-qualified deferred compensation plan was terminated and all remaining assets were paid to participants during the first quarter of 2018. See Note 5 and Note 16 for additional discussion of investments.
Asset Retirement Obligations.
The Company owns oil and natural gas assets that require expenditures to plug, abandon and remediate associated property at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded at the estimated present value at the time the wells are drilled or
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
acquired, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the asset is sold and the liability is removed. Both the accretion and the depreciation are included in the consolidated statements of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 12 for further discussion of the Company’s asset retirement obligations.
Revenue Recognition and Natural Gas Balancing.
Sales of oil, natural gas and NGLs are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck, net of royalties, discounts and allowances, as applicable. Additionally, the Successor Company made an accounting policy election on the Emergence Date to deduct transportation costs from oil, natural gas and NGL revenues. This resulted in presenting $27.7 million, $29.1 million and $7.4 million of transportation costs as a reduction from revenues in the years ended December 31, 2018 and 2017, and the Successor 2016 Period, respectively, versus presenting $26.2 million of these costs as production expenses in the Predecessor 2016 Period. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are included in production tax expense in the consolidated statements of operations. See Note 17 for further information on the Company's accounting policies related to revenues.
The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the Company's ownership entitles it to sell. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions of $1.7 million and $1.6 million at December 31, 2018 and 2017, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets.
Allocation of Share-Based Compensation.
For both the Successor and Predecessor Companies, equity compensation provided to employees directly involved in exploration and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses, production expenses, and other operating expense in the accompanying consolidated statements of operations.
Income Taxes.
Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized.
The Company has elected an accounting policy in which interest and penalties on income taxes resulting from the underpayment or late payment of income taxes due to a taxing authority or relating to income tax contingencies are presented as a component of the income tax provision, rather than as interest expense.
Earnings per Share.
Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the Successor Company consist of unvested restricted stock awards and warrants, using the treasury method, and convertible senior notes, using the if-converted method. Potentially dilutive securities for the Predecessor Company consist of unvested restricted stock awards and restricted share units, using the treasury method, and convertible preferred stock and convertible senior notes, using the if-converted method.
Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the warrants were exercised are assumed to be used to repurchase shares at the average market price.
During the Successor 2016 Period, the Company assumed the conversion of the Convertible Notes to common stock under the if-converted method and determined if it was more dilutive than including the expense associated with the Convertible Notes in the computation of income available to common stockholders during the period the Convertible Notes were outstanding. The Predecessor Company also assumed the conversion of the preferred stock or Convertible Senior Unsecured Notes to common stock under the if-converted method and determined if it was more dilutive than including the preferred stock dividends or expense associated with the Convertible Senior Unsecured Notes, respectively, in the computation
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
of income available to common stockholders. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 21 for the Company’s earnings per share calculation.
Commitments and Contingencies.
Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Environmental liabilities related to future costs are recorded on an undiscounted basis when assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 13 for discussion of the Company’s commitments and contingencies.
Concentration of Risk.
All of the Company’s commodity derivative transactions have been carried out in the over-the-counter market, which involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s commodity derivative transactions have an “investment grade” credit rating. The Company monitors the credit ratings of its commodity derivative counterparties on an ongoing basis and considers their credit default risk ratings in determining the fair value of its commodity derivative contracts. The Company’s commodity derivative contracts are with multiple counterparties to minimize exposure to any individual counterparty.
If the Company defaults on its credit facility it will also default on commodity derivative contracts with counterparties that are lenders under the credit facility. The Company does not require collateral or other security from counterparties to support commodity derivative instruments. The Company has master netting agreements with all of its commodity derivative counterparties, which allow the Company to net its commodity derivative assets and liabilities for like commodities and derivative instruments with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the commodity derivative contracts. The Company’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the credit facility can be offset against any amounts owed to the same counterparty under the credit facility.
The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners are primarily independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.
Purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, large oil and natural gas companies and gas pipeline companies. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect its ability to sell the oil, natural gas and NGLs it produces.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
% of Revenue
|
December 31, 2018 - Successor
|
|
|
|
Targa Midstream Services L.P.
|
$
|
126,548
|
|
36.2
|
%
|
Plains Marketing, L.P.
|
$
|
102,182
|
|
29.2
|
%
|
Sinclair Crude Company
|
$
|
62,623
|
|
17.9
|
%
|
|
|
|
|
December 31, 2017 - Successor
|
|
|
|
Targa Pipeline Mid-Continent West OK LLC
|
$
|
144,583
|
|
40.5
|
%
|
Plains Marketing, L.P.
|
$
|
117,927
|
|
33.0
|
%
|
|
|
|
|
Period from October 2, 2016 through December 31, 2016 - Successor
|
|
|
|
Targa Pipeline Mid-Continent West OK LLC
|
$
|
35,845
|
|
36.4
|
%
|
Plains Marketing, L.P.
|
$
|
32,022
|
|
32.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from January 1, 2016 through October 1, 2016 - Predecessor
|
|
|
|
Plains Marketing, L.P.
|
$
|
110,370
|
|
37.6
|
%
|
Targa Pipeline Mid-Continent West OK LLC
|
$
|
108,238
|
|
36.8
|
%
|
Recent Accounting Pronouncements.
The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a single comprehensive model for entities to use in accounting for revenues from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," which deferred the effective date of ASU 2014-09 to January 1, 2018, for the Company. The ASU required adoption using either the retrospective transition method, which required restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilized a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. The Company adopted Topic 606 and all the related amendments (the “new revenue standard”) on January 1, 2018, using the modified retrospective transition method. See Note 17 for further discussion of the adoption of the new revenue standard.
The FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory,” which removed the prohibition in ASC 740 against the immediate recognition of current and deferred income tax effects of intra-entity transfers of assets other than inventory. The amendments in this ASU were effective for the Company on January 1, 2018, with early adoption permitted on January 1, 2017. The ASU required application on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company adopted the ASU on January 1, 2018. There was no impact to the Company’s consolidated financial statements and related disclosures upon adoption.
The FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic: 610-20): Clarifying the Scope of Asset Derecognition Guidance and the Accounting for Partial Sales of Nonfinancial Assets,” which helps filers determine the guidance applicable for gain/loss recognition subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers. The amendments also clarified that the derecognition of all businesses except those related to conveyances of oil and gas rights or contracts with customers should be accounted for in accordance with the derecognition and deconsolidation guidance in Topic 810, Consolidation. The Company adopted the ASU on January 1, 2018, using the modified retrospective transition method. Under this transition method the Company could have elected to apply this guidance retrospectively either to all contracts at the date of initial application or only to contracts that are not completed contracts at the date of initial application. The Company elected to evaluate only contracts that are not completed contracts. As there were no uncompleted contracts at January 1, 2018, there was no impact to the Company’s consolidated financial statements and related disclosures upon adoption.
The FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the disclosure Requirements for Fair Value Measurement," which removes, modifies or adds disclosure requirements regarding fair value measurements. The amendments in this ASU are effective for all entities beginning after December 15, 2019, with amendments on changes in unrealized gains and losses, the range and weighted average of significant unobservable inputs used
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty requiring prospective adoption and all other amendments requiring retrospective adoption. Early adoption is permitted and the Company elected to adopt this ASU during the third quarter of 2018, which resulted in a change to the Company's fair value measurement disclosures on a prospective basis, but had no impact on its consolidated financial statements.
Recent Accounting Pronouncements Not Yet Adopted.
The FASB issued ASU 2016-02, “Leases (Topic 842),” and other associated ASU's related to Topic 842 which requires lessees to recognize the assets and liabilities for the rights and obligations of all leases with a term greater than 12 months (long-term) on the balance sheet. Leases will be classified as financing or operating expenses, with the classification affecting the pattern and classification of expense recognition in the income statement. Leases to explore for or use oil and natural gas are not impacted by this guidance. This topic is effective for the Company on January 1, 2019. Early adoption is permitted.
Topic 842 provides a number of optional practical expedients in transition. The Company plans to elect the ‘package of practical expedients,’ and therefore will not have to reassess its prior conclusions about lease identification, lease classification and initial indirect costs. The Company also plans to elect the land easement practical expedient. The Company will also utilize the short-term lease recognition exemption, which means assets and liabilities will not be recognized for the rights and obligations of qualifying leases, including existing short-term leases of those assets in transition. The Company does not plan to elect the use-of-hindsight. Upon adoption, the Company anticipates (i) recognizing assets and liabilities for the rights and obligations of its vehicle and equipment leases and, (ii) providing new disclosures about the Company’s leasing activities. The Company has completed the implementation of a lease contract management system and is finalizing processes and internal controls to properly identify, classify, measure and recognize new (or modified) leases on and after the date of adoption. The Company will adopt Topic 842 using a modified retrospective approach by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company is still finalizing its evaluation of the January 1, 2019 adoption. The impact to recognize the assets and liabilities for the rights and obligations of the Company's leases on the balance sheet is not expected to be material at adoption. New disclosures will be required in the first quarter of 2019 to present information related to the Company's leases, including the Company's short-term leases, which are not required to be presented on the balance sheet utilizing the short-term lease recognition exemption.
The FASB issued ASU 2016-13, “Financial Instruments —Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments,” which changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for the interim and annual periods beginning after December 31, 2018, and will be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company does not plan to early adopt and is currently evaluating the effect the guidance will have on its consolidated financial statements; however, the impact is not expected to be material.
3. Supplemental Cash Flow Information
Supplemental disclosures to the consolidated statements of cash flows are presented below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
Supplemental Disclosure of Cash Flow Information
|
|
|
|
|
|
|
|
|
Cash paid for reorganization items
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
(55,606)
|
Cash paid for interest, net of amounts capitalized
|
$
|
(4,045)
|
|
$
|
(2,438)
|
|
$
|
(1,183)
|
|
|
$
|
(104,609)
|
Cash received (paid) for income taxes
|
$
|
4,381
|
|
$
|
4,348
|
|
$
|
—
|
|
|
$
|
(28)
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosure of Noncash Investing and Financing Activities
|
|
|
|
|
|
|
|
|
Cumulative effect of adoption of ASU 2015-02
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
(247,566)
|
Property, plant and equipment transferred in settlement of contract
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
215,635
|
Change in accrued capital expenditures
|
$
|
(15,861)
|
|
$
|
(28,999)
|
|
$
|
10,630
|
|
|
$
|
25,045
|
Equity issued for debt
|
$
|
—
|
|
$
|
(268,779)
|
|
$
|
(13,001)
|
|
|
$
|
(4,409)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
4. Acquisitions and Divestitures of Oil and Gas Properties
Successor Acquisitions and Divestitures
2018 Divestitures
Divestiture of Permian Basin Properties.
On November 1, 2018, the Company sold substantially all of its oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, primarily located in Andrews County, TX, along with 13,125,000 common units representing a 25% equity interest in the Permian Trust, to an independent third party for $14.5 million in cash, subject to certain remaining post-closing adjustments, and reduced its asset retirement obligations by approximately $26.9 million. The CBP assets and interest in the Permian Trust included 1,066 producing wells within the Permian Trust's area of mutual interest, certain wells not associated with the Permian Trust, a field office, and all equipment, inventory and yards associated with the Company's CBP operations. As a result of this divestiture, the Company no longer has any obligations associated with the Permian Trust. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the divestiture was accounted for as an adjustment to the full cost pool with no gain or loss recognized on the sale.
2018 Acquisitions
Acquisition of Oil and Natural Gas Interests.
On November 2, 2018, the Company acquired an interest in certain oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas for approximately $22.5 million in net consideration, net of post-closing adjustments, and assumed asset retirement obligations of approximately $6.4 million. The acquired assets primarily consist of interests in 1,199 producing wells, approximately 80% of which are operated by the Company, an additional 11.1% working interest in approximately 397,000 gross (44,000 net) acres across the Mid-Continent, and an additional 13.2% working interest ownership in the Company's saltwater gathering and disposal system in the Mississippian Lime.
2017 Acquisitions
Acquisition of Properties.
On February 10, 2017, the Company acquired assets consisting of approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.8 million in cash, net of post-closing adjustments. Also included in the acquisition were working interests in four wells previously drilled on the acreage.
2017 Divestitures
2017 Property Divestitures.
In 2017, the Company divested various non-core oil and natural gas properties for approximately $17.1 million in cash. All of these divestitures were accounted for as adjustments to the full cost pool with no gain or loss recognized.
Predecessor Acquisitions and Divestitures
2016 Divestiture
Divestiture of West Texas Overthrust Properties and Release from Treating Agreement.
In January 2016, the Company paid $11.0 million in cash and transferred ownership of substantially all of its oil and natural gas properties and midstream assets located in the Piñon field in the WTO to Occidental and was released from all past, current and future claims and obligations under an existing 30 year treating agreement between the companies. As of the date of the transaction, the Company had accrued approximately $111.9 million for penalties associated with shortfalls in meeting its delivery requirements under the agreement since it became effective in late 2012. The Company recognized a loss of approximately $89.1 million on the termination of the treating agreement and the cease-use of transportation agreements that supported production from the Piñon field and reduced its asset retirement obligations associated with its oil and natural gas properties by $34.1 million.
See Note 7 for discussion of non-oil and gas divestitures.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
5. Fair Value Measurements
The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, restricted cash, accounts receivable, prepaid expenses, certain other current and non-current assets, accounts payable and accrued expenses and other current liabilities included in the consolidated balance sheets approximated fair value at December 31, 2018, and December 31, 2017. As a result, these financial assets and liabilities are not discussed below. The fair values of property, plant and equipment and related impairments, which are calculated using Level 3 inputs, are discussed in Note 7.
|
|
|
|
|
|
|
|
|
Level 1
|
|
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
|
|
|
|
Level 2
|
|
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
|
|
|
|
Level 3
|
|
Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (
i.e.,
supported by little or no market activity).
|
Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of these inputs requires judgment, which may affect the valuation and placement of these assets and liabilities within the fair value hierarchy levels. The market for the Company’s financial assets and liabilities, any associated credit risk and other factors are considered in calculating the fair values. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities classified in Level 2 of the hierarchy as of December 31, 2018, and Level 1 and Level 2 as of December 31, 2017, as described below.
Level 1 Fair Value Measurements
Investments.
The fair value of investments, which consisted of assets held in the Company’s non-qualified deferred compensation plan, was based on quoted market prices. See Note 2 and Note 16 for additional information.
Level 2 Fair Value Measurements
Commodity Derivative Contracts.
The fair values of the Company’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets. Fair value is determined through the use of a discounted cash flow model or option pricing model using the applicable inputs discussed above. The Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit default risk rating, as applicable, in determining the fair value of these derivative contracts. Credit default risk ratings are based on current published credit default swap rates.
Fair Value - Recurring Measurement Basis
The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands):
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
|
|
|
|
|
|
Netting(1)
|
|
Assets/Liabilities at Fair Value
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts
|
$
|
—
|
|
$
|
5,286
|
|
$
|
—
|
|
$
|
—
|
|
$
|
5,286
|
|
|
|
|
|
|
|
|
|
|
|
$
|
—
|
|
$
|
5,286
|
|
$
|
—
|
|
$
|
—
|
|
$
|
5,286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
|
|
|
|
|
|
Netting(1)
|
|
Assets/Liabilities at Fair Value
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts
|
$
|
—
|
|
$
|
5,582
|
|
$
|
—
|
|
(4,272)
|
|
$
|
1,310
|
Investments
|
5,072
|
|
—
|
|
—
|
|
—
|
|
5,072
|
|
$
|
5,072
|
|
$
|
5,582
|
|
$
|
—
|
|
$
|
(4,272)
|
|
$
|
6,382
|
Liabilities
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts
|
$
|
—
|
|
$
|
18,467
|
|
$
|
—
|
|
$
|
(4,272)
|
|
$
|
14,195
|
|
$
|
—
|
|
$
|
18,467
|
|
$
|
—
|
|
$
|
(4,272)
|
|
$
|
14,195
|
____________________
1.
Represents the impact of netting assets and liabilities with counterparties where the right of offset exists.
Transfers.
During the years ended December 31, 2018 and 2017, the Successor 2016 Period and Predecessor 2016 Period, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.
Fair Value of Financial Instruments - Long-Term Debt
The fair value of the Building Note was measured using a discounted cash flow analysis, which is classified as a Level 2 input in the fair value hierarchy. The Building Note was paid in full during the first quarter of 2018. The estimated fair values and carrying values of the Company’s long-term debt are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
|
December 31, 2017
|
|
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
Building Note
|
$
|
—
|
|
$
|
—
|
|
$
|
42,526
|
|
$
|
37,502
|
See Note 10 for discussion of the Company’s long-term debt.
Fair Value of Non-Financial Assets and Liabilities
See Note 8 for discussion of the Company’s impairment valuations.
6. Accounts Receivable
A summary of accounts receivable is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2018
|
|
2017
|
Oil, natural gas and NGL sales
|
$
|
31,780
|
|
$
|
35,301
|
Joint interest billing
|
13,083
|
|
29,505
|
Oil and natural gas services
|
604
|
|
639
|
Other
|
1,331
|
|
7,106
|
Total accounts receivable
|
46,798
|
|
72,551
|
Less: allowance for doubtful accounts
|
(1,295)
|
|
(1,274)
|
Total accounts receivable, net
|
$
|
45,503
|
|
$
|
71,277
|
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The following table presents the balance and activity in the allowance for doubtful accounts for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
Beginning balance
|
$
|
1,274
|
|
$
|
880
|
|
$
|
—
|
|
|
$
|
4,847
|
Additions charged to costs and expenses(1)
|
758
|
|
397
|
|
880
|
|
|
16,695
|
Deductions(2)
|
(737)
|
|
(3)
|
|
—
|
|
|
(751)
|
Impact of fresh start accounting
|
—
|
|
—
|
|
—
|
|
|
(20,791)
|
Ending balance
|
$
|
1,295
|
|
$
|
1,274
|
|
$
|
880
|
|
|
$
|
—
|
____________________
1.
The Predecessor 2016 Period includes a
$16.7 million addition for a joint interest account receivable after determining that future collection was doubtful when the joint interest owner filed for bankruptcy.
2.
Deductions represent the write-off of receivables and collections of amounts for which an allowance had previously been established.
7. Property, Plant and Equipment
Property, plant and equipment consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2018
|
|
2017
|
Oil and natural gas properties
|
|
|
|
Proved
|
$
|
1,269,091
|
|
$
|
1,056,806
|
Unproved
|
60,152
|
|
100,884
|
Total oil and natural gas properties
|
1,329,243
|
|
1,157,690
|
Less accumulated depreciation, depletion and impairment
|
(580,132)
|
|
(460,431)
|
Net oil and natural gas properties capitalized costs
|
749,111
|
|
697,259
|
|
|
|
|
Land
|
4,400
|
|
4,500
|
Electrical infrastructure
|
131,176
|
|
131,010
|
Non-oil and natural gas equipment
|
13,458
|
|
26,809
|
Buildings and structures
|
77,148
|
|
79,548
|
Total
|
226,182
|
|
241,867
|
Less accumulated depreciation and amortization
|
(25,344)
|
|
(15,886)
|
Other property, plant and equipment, net
|
200,838
|
|
225,981
|
Total property, plant and equipment, net
|
$
|
949,949
|
|
$
|
923,240
|
The average rates used for depreciation and depletion of oil and natural gas properties were $10.32 per Boe in 2018, $7.92 per Boe in 2017, $8.31 per Boe in the Successor 2016 Period and $6.05 per Boe in the Predecessor 2016 Period.
See Note 8 for discussion of impairment of other property, plant and equipment.
The Company had approximately $10.6 million in assets classified as held for sale in the other current assets line of the accompanying consolidated balance sheet at December 31, 2017. Approximately $9.3 million of this total was related to one of the Company’s properties located in downtown Oklahoma City, OK, which was classified as held for sale in the fourth quarter of 2017 and sold during the second quarter of 2018 for a net amount of approximately $10.4 million, including transaction fees. The resulting gain of $1.1 million was recorded in other operating expense on the accompanying condensed consolidated statements of operations for the year ended December 31, 2018.
Additionally, during the first quarter of 2018, the Company classified its remaining midstream generator assets as held for sale. These assets had a carrying value of $5.7 million which exceeded the estimated net realizable value of $1.6 million
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
based on expected sales prices obtained from third parties. As a result, the Company recorded an impairment of $4.1 million for the year ended December 31, 2018. The midstream generator assets were sold during the second quarter of 2018 with no gain or loss recognized on the sale. No significant assets were classified as held for sale at December 31, 2018.
Costs Excluded from Amortization
The following table summarizes the costs, by year incurred, related to unproved properties, which were excluded from oil and natural gas properties subject to amortization at December 31, 2018 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Cost Incurred
|
|
|
|
|
|
|
|
Total
|
|
2018
|
|
2017
|
|
2016
|
|
2015 and Prior
|
Property acquisition
|
$
|
59,522
|
|
$
|
3,859
|
|
$
|
20,647
|
|
$
|
13,735
|
|
$
|
21,281
|
Exploration
|
630
|
|
13
|
|
323
|
|
243
|
|
51
|
Total costs incurred
|
$
|
60,152
|
|
$
|
3,872
|
|
$
|
20,970
|
|
$
|
13,978
|
|
$
|
21,332
|
For leases that do not have existing production that would otherwise extend the lease term, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a
three
to
five
year period from the original lease date. For leases that are held by production, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a 10-year period from the original lease date. In addition, the Company’s internal engineers evaluate all properties on a quarterly basis.
8. Impairment
The Company analyzes various property, plant and equipment for impairment when certain triggering events occur by comparing the carrying values of the assets to their estimated fair values. Estimated fair values of drilling, midstream, electrical transmission and other assets were determined in accordance with the policies discussed in Note 2.
Impairment for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
Full cost pool ceiling limitation(1)(2)
|
|
$
|
—
|
|
$
|
—
|
|
$
|
319,087
|
|
|
$
|
657,392
|
Drilling assets(3)(4)
|
|
22
|
|
4,019
|
|
—
|
|
|
3,511
|
Electrical infrastructure assets(5)
|
|
—
|
|
—
|
|
—
|
|
|
55,600
|
Midstream assets(6)
|
|
4,148
|
|
—
|
|
—
|
|
|
1,691
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
4,170
|
|
$
|
4,019
|
|
$
|
319,087
|
|
|
$
|
718,194
|
____________________
1.
Impairment recorded in the Successor 2016 Period resulted from the application of fresh start accounting
, whereby the fair value of the Successor Company full cost pool was determined based upon forward strip oil and natural gas prices as of the Emergence Date. Because these prices were higher than the 12-month weighted average prices used in the full cost ceiling limitation calculation at December 31, 2016, the Successor Company incurred a ceiling test impairment.
2.
Impairment recorded for the Predecessor Company in 2016 was due to full cost ceiling limitations recognized in each of the first three quarters of 2016. The impairment
recorded in the first two quarters of 2016 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued throughout 2015 and the first half of 2016. The impairment recorded in the third quarter of 2016 resulted primarily from downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes.
3.
Impairment recorded in the year
s ended December 31, 2018 and 2017 reflects the write-down of remaining drilling and oilfield services assets classified as held for sale to net realizable value.
4.
Impairment recorded in the Predecessor 2016 Period
resulted from the write-down of certain drilling assets after the Company discontinued drilling operations in the Permian region.
5.
Impairment in the Predecessor 2016 Period resulted from a decrease in projected Mid-Continent production volumes supporting the system’s usage.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
6.
Im
pairment recorded in 2018 reflects the write down of midstream generator assets classified as held for sale to the net realizable value. The impairment recorded in the Predecessor 2016 Period resulted from the evaluation of certain midstream pipe inventory, natural gas compressors, gas treating plants and a CO
2
compressor station after determining that their future use was limited.
9. Accounts Payable and Accrued Expenses
Accounts payable and accrued expenses consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2018
|
|
|
2017
|
Accounts payable and other accrued expenses
|
$
|
78,219
|
|
|
$
|
90,423
|
Payroll and benefits
|
12,891
|
|
|
21,475
|
Production payable
|
12,767
|
|
|
18,059
|
Taxes payable
|
5,350
|
|
|
3,983
|
Drilling advances
|
2,031
|
|
|
3,830
|
Accrued interest
|
539
|
|
|
1,385
|
Total accounts payable and accrued expenses
|
$
|
111,797
|
|
|
$
|
139,155
|
|
|
|
|
|
10. Long-Term Debt
Long-term debt consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2018
|
|
2017
|
Credit facility
|
$
|
—
|
|
$
|
—
|
Building Note
|
—
|
|
37,502
|
Total debt
|
—
|
|
37,502
|
Less: current maturities of long-term debt
|
—
|
|
—
|
Long-term debt
|
$
|
—
|
|
$
|
37,502
|
Credit
Facility.
On February 10, 2017, the Company's First Lien Exit Facility was refinanced and replaced by a new $600.0 million credit facility with a $425.0 million available borrowing base. The borrowing base under the credit facility was reduced from $425.0 million to $350.0 million during the October 2018 semi-annual redetermination. The next borrowing base redetermination is scheduled for April 1, 2019. The credit facility matures on March 31, 2020. Outstanding borrowings under the credit facility bear interest based on a pricing grid tied to borrowing base utilization of (a) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum, or (b) the base rate plus an applicable margin that varies from 2.00% to 3.00% per annum. Interest on base rate borrowings is payable quarterly in arrears and interest on LIBOR borrowings is payable every one, two, three or six months, at the election of the Company. Quarterly, the Company pays commitment fees assessed at annual rates of 0.50% on any available portion of the credit facility. The Company has the right to prepay loans under the credit facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans. Upon refinancing of the First Lien Exit Facility, $50.0 million maintained in a restricted cash collateral account, as required by the terms of the First Lien Exit Facility, was released to the Company.
The credit facility is secured by (i) first-priority mortgages on at least 95% of the PV-9 valuation of all the Company's proved reserves included in the reserve report most recently provided to the lenders, (ii) a first-priority perfected pledge of substantially all of the capital stock owned by each credit party and equity interests in the Royalty Trusts that are owned by a credit party and (iii) a first-priority perfected security interest in substantially all the cash, cash equivalents, deposits, securities and other similar accounts, and other tangible and intangible assets of the credit parties (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing).
As of the end of each fiscal quarter, the credit facility requires the Company to maintain (i) a maximum consolidated total net leverage ratio of no greater than 3.50 to 1.00 and (ii) a minimum consolidated interest coverage ratio of no less than
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
2.25 to 1.00. These financial covenants are subject to customary cure rights. The Company was in compliance with all applicable financial covenants under the credit facility at the end of each fiscal quarter in 2018.
The credit facility contains customary affirmative and negative covenants, including compliance with certain laws (including environmental laws, ERISA and anti-corruption laws), maintaining required insurance, delivering quarterly and annual financial statements, oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on incurring liens and indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. The Company was in compliance with these covenants as of December 31, 2018.
The credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $25.0 million or more; bankruptcy; judgments involving a liability of $25.0 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods.
Changes in the composition of the Company's Board resulting from the 2018 annual meeting in June 2018 may have been an event of default under the change in control provisions in the credit facility. However, the Company entered into a consent and waiver agreement with the administrative agent and certain lenders constituting the majority lenders under the credit facility. The consent and waiver agreement waived any event of default which might have occurred as a result of the change in the composition of the members of the Company’s Board and recognized the new members of the Board as existing members of the Board under the definition of change in control in the credit agreement.
The Company had no amounts outstanding under the credit facility at December 31, 2018 and $5.2 million in outstanding letters of credit, which reduce availability under the credit facility on a dollar-for-dollar basis.
First Lien Exit Facility.
On the Emergence Date, the Company entered into the First Lien Exit Facility with the lenders party thereto and Royal Bank of Canada, as administrative agent and issuing lender. The First Lien Exit Facility had a borrowing base of $425.0 million and was set to mature on February 4, 2020. Outstanding borrowings bore interest at a rate equal to either (a) a base rate plus an applicable rate of 3.75% per annum or (b) LIBOR plus 4.75% per annum, subject to a 1.00% LIBOR floor. Interest on base rate borrowings was payable quarterly in arrears and interest on LIBOR borrowings was payable every one, two, three or six months. Quarterly commitment fees were assessed at annual rates of 0.50% on any available portion of the First Lien Exit Facility. The Company had the right to prepay loans under the First Lien Exit Facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans.
Convertible Notes.
As discussed in Note 1, on the Emergence Date, pursuant to the terms of the Plan, the Company issued approximately $281.8 million principal amount of Convertible Notes, which did not bear regular interest and were set to mature and mandatorily convert into shares of Common Stock on October 4, 2020, unless repurchased, redeemed or converted prior to that date. Under fresh start accounting, the Convertible Notes were recorded at their fair value of $445.7 million, which resulted in a premium of $163.9 million being recorded to additional paid in capital. The Company’s obligations pursuant to the Convertible Notes were fully and unconditionally guaranteed, jointly and severally, by each of the guarantors of the First Lien Exit Facility.
The Convertible Notes were initially convertible at a conversion rate of 0.05330841 shares of Common Stock per $1.00 principal amount of Convertible Notes, which represented, approximately 15.0 million total shares of common stock. The conversion rate was subject to customary anti-dilution adjustments. Convertible Notes holders could convert them at any time up to, and including, the business day prior to the maturity date. Between the Emergence Date and December 31, 2016, holders requested conversion of approximately $13.0 million of the Convertible Notes into approximately 0.7 million shares of Common Stock. Additionally, from January 1, 2017 to February 9, 2017, holders requested conversion of approximately $5.1 million of the Convertible Notes into approximately 0.3 million shares of Common Stock. The remaining $263.7 million par value of outstanding Convertible Notes mandatorily converted into 14.1 million shares of Common Stock when the First Lien Exit Facility was refinanced on February 10, 2017, after the determination by the Successor Company’s board of directors in good faith that: (a) the refinancing provided for terms that were materially more favorable to the Company and (b) causing a conversion was not the primary purpose of the refinancing.
Building Note
.
As discussed in Note 1, on the Emergence Date, the Company entered into the Building Note which had an initial principal amount of $35.0 million, and was set to mature on October 2, 2021. The Company sold the Building Note for net proceeds of $26.8 million which were then remitted to unsecured creditors on the Emergence Date. The Company repaid the Building Note in full in February 2018. Interest was payable on the Building Note at 6% per annum for the first year
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
following the Emergence Date, 8% per annum for the second year following the Emergence Date, and 10% thereafter through maturity. Interest costs were payable in-kind until 90 days after the refinancing of the First Lien Exit Facility. Approximately $1.3 million in in-kind interest costs were added to the Building Note principal from the Emergence Date through May 11, 2017. Interest became payable in cash after that date. The Building Note became prepayable in whole or in part without premium or penalty when the First Lien Exit Facility was refinanced. Under fresh start accounting, the Building Note was initially recorded at a fair value of $36.6 million and the resulting premium was being amortized to interest expense over the term of the Building Note. When the Building Note was repaid, the remaining unamortized premium of $1.2 million was recognized as a gain on extinguishment of debt in the statement of operations for the year ended December 31, 2018.
11. Derivatives
Commodity Derivatives
The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. On occasion, the Company has attempted to manage this risk on a portion of its forecasted oil or natural gas production sales through the use of commodity derivative contracts. None of the Company’s commodity derivative contracts may be terminated prior to contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. Commodity derivative contracts are settled on a monthly basis. On a quarterly basis, the commodity derivative contract valuations are adjusted to the mark-to-market valuation. At December 31, 2018, the Company’s commodity derivative contracts consisted of natural gas fixed price swaps. The Company receives a fixed price for these contracts and pays a floating market price to the counterparty over a specified period for a contracted volume.
The Company recorded loss (gain) on commodity derivative contracts of $17.2 million and $(24.1) million for the years ended December 31, 2018 and 2017, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash payments (receipts) upon settlement of $35.3 million and $(7.3) million, respectively. Approximately $0.8 million of the payments made in 2018 relate to early settlements due to unwinding all oil derivative contracts in December 2018.
The Company recorded loss on commodity derivative contracts of $25.7 million and $4.8 million for the Successor 2016 Period and the Predecessor 2016 Period, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash receipts upon settlement of $7.7 million and $72.6 million, respectively. The net receipts for the Predecessor 2016 Period include $17.9 million of cash receipts due to early settlements of certain derivative contracts after the Chapter 11 filings occurred.
In December 2018, we entered into early settlements of all open crude oil swaps covering nine thousand bbls/day of production in December 2018 at an average strike price of $56.12, and five thousand bbls/day of production during 2019 at an average strike price of $54.29. Simultaneously, the Company entered into natural gas swaps for the first quarter of 2019. The Board and management of the Company are continuing to evaluate the futures market for oil and natural gas in an attempt to protect short-term cash flow and to mitigate exposure to adverse oil and natural gas price changes.
Master Netting Agreements and the Right of Offset.
The Company has master netting agreements with all of its commodity derivative counterparties and has presented its derivative assets and liabilities with the same counterparty on a net basis by commodity type in the consolidated balance sheets. As a result of the netting provisions, the Company's maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from its counterparties. As of December 31, 2018, the counterparties to the Company’s open commodity derivative contracts consisted of four financial institutions, all of which are also lenders under the Company’s credit facility. The Company is not required to post additional collateral under its commodity derivative contracts as all of the counterparties to the Company’s commodity derivative contracts share in the collateral supporting the Company’s credit facility.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative liability positions, the applicable portion of shared collateral under the credit facility as of December 31, 2018 and 2017 (in thousands):
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Amounts
|
|
Gross Amounts Offset
|
|
Amounts Net of Offset
|
|
Financial Collateral
|
|
Net Amount
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts - current
|
|
$
|
5,286
|
|
$
|
—
|
|
$
|
5,286
|
|
$
|
—
|
|
$
|
5,286
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,286
|
|
$
|
—
|
|
$
|
5,286
|
|
$
|
—
|
|
$
|
5,286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Amounts
|
|
Gross Amounts Offset
|
|
Amounts Net of Offset
|
|
Financial Collateral
|
|
Net Amount
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts - current
|
|
$
|
5,582
|
|
$
|
(4,272)
|
|
$
|
1,310
|
|
$
|
—
|
|
$
|
1,310
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,582
|
|
$
|
(4,272)
|
|
$
|
1,310
|
|
$
|
—
|
|
$
|
1,310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts - current
|
|
$
|
14,899
|
|
$
|
(4,272)
|
|
$
|
10,627
|
|
$
|
(10,627)
|
|
$
|
—
|
Derivative contracts - noncurrent
|
|
3,568
|
|
—
|
|
3,568
|
|
(3,568)
|
|
—
|
Total
|
|
$
|
18,467
|
|
$
|
(4,272)
|
|
$
|
14,195
|
|
$
|
(14,195)
|
|
$
|
—
|
At December 31, 2018, the Company’s open commodity derivative contracts consisted of the following:
Natural Gas Price Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional (MMcf)
|
|
Weighted Average
Fixed Price
|
January 2019 - March 2019
|
4,500
|
|
$
|
4.28
|
Fair Value of Derivatives
The following table presents the fair value of the Company’s derivative contracts on a gross basis without regard to same-counterparty netting (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
December 31,
|
Type of Contract
|
|
Balance Sheet Classification
|
|
2018
|
|
2017
|
Derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price swaps
|
|
Derivative contracts - current
|
|
$
|
5,286
|
|
$
|
5,582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liabilities
|
|
|
|
|
|
|
Oil price swaps
|
|
Derivative contracts - current
|
|
—
|
|
(14,899)
|
|
|
|
|
|
|
|
Oil price swaps
|
|
Derivative contracts - noncurrent
|
|
—
|
|
(3,568)
|
|
|
|
|
|
|
|
Total net derivative contracts
|
|
|
|
$
|
5,286
|
|
$
|
(12,885)
|
See Note 5 for additional discussion of the fair value measurement of the Company’s derivative contracts.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
12. Asset Retirement Obligations
The following table presents the balance and activity of the Company’s asset retirement obligations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
Beginning balance
|
$
|
77,544
|
|
$
|
106,481
|
|
$
|
92,413
|
|
|
$
|
103,578
|
Liability incurred upon acquiring and drilling wells
|
7,079
|
|
1,336
|
|
121
|
|
|
505
|
Revisions in estimated cash flows(1)
|
870
|
|
(28,565)
|
|
12,397
|
|
|
—
|
Liability settled or disposed in current period(2)
|
(31,967)
|
|
(11,308)
|
|
(540)
|
|
|
(36,979)
|
Accretion
|
6,538
|
|
9,600
|
|
2,090
|
|
|
4,365
|
Impact of fresh start accounting
|
—
|
|
—
|
|
—
|
|
|
20,944
|
Ending balance
|
60,064
|
|
77,544
|
|
106,481
|
|
|
92,413
|
Less: current portion
|
25,393
|
|
41,017
|
|
66,154
|
|
|
65,678
|
Asset retirement obligations, net of current
|
$
|
34,671
|
|
$
|
36,527
|
|
$
|
40,327
|
|
|
$
|
26,735
|
____________________
1.
Revisions for the year
s ended December 31, 2018 and 2017, and the Successor 2016 Period relate primarily to changes in estimated well lives due to changes in oil and natural gas prices and changes in plugging cost estimates.
2.
Liability settled or disposed for the
year ended December 31, 2018 includes $26.9 million associated with the Permian Properties sold in November 2018. Liability settled or disposed for the Predecessor 2016 Period includes $34.1 million associated with the WTO Properties sold in January 2016.
13. Commitments and Contingencies
Included below is a discussion of the Company's various future commitments as of December 31, 2018. The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets.
Third-party drilling rig agreements.
As of December 31, 2018, the Company had third-party drilling rig agreements with various terms extending to May 2019 to ensure rig availability in its key operating areas. Future commitments as of December 31, 2018 total approximately $3.6 million.
Leases and other.
As of December 31, 2018, the Company had commitments for leases and other agreements totaling approximately $4.8 million. These commitments are primarily for fleet vehicles, maintenance services, office equipment, and purchase obligations related to software services. Rental expense related to these leases was not significant for the years ended December 31, 2018, December 31, 2017, the Successor 2016 Period or the Predecessor 2016 Period.
Litigation and Claims.
As previously disclosed, on May 16, 2016, the Debtors filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan on September 9, 2016, and the Debtors subsequently emerged from bankruptcy on October 4, 2016.
Pursuant to the Plan, claims against the Company were discharged without recovery in each of the following consolidated cases (the “Cases”):
• In re SandRidge Energy, Inc. Securities Litigation, Case No. 5:12-cv-01341-LRW, USDC, Western District of
Oklahoma
• Ivan Nibur, Lawrence Ross, Jase Luna, Matthew Willenbucher, and the Duane & Virginia Lanier Trust v. SandRidge
Mississippian Trust I, et al., Case No. 5:15-cv-00634-SLP, USDC, Western District of Oklahoma
• Barton W. Gernandt Jr., et al. v. SandRidge Energy, Inc., Case No. 5:15-cv-00834-D, USDC, Western District of
Oklahoma
On November 8, 2018, the court in the Gernandt case granted the defendants’ respective motions to dismiss and dismissed the action with prejudice.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Although the remaining two Cases have not been dismissed against certain former officers and directors who remain defendants in the Cases, the Company remains as a nominal defendant in each of the Cases so that any of the respective plaintiffs may seek to recover proceeds from any applicable insurance policies or proceeds. In each of the Cases, to the extent liability exceeds the amount of available insurance proceeds, the Company may owe indemnity obligations to its former officers and/or directors who remain as defendants in such action. An estimate of reasonably probable losses associated with any of the Cases cannot be made at this time. The Company has not established any reserves relating to any of the Cases.
In addition to the matters described above, the Company is involved in various lawsuits, claims and proceedings which are being handled and defended by the Company in the ordinary course of business. Pursuant to the terms of the SandRidge Mississippian Trust I and SandRidge Mississippian Trust II, the Company is obligated to indemnify each Royalty Trust, for as long as the Trusts exist, against losses, claims, damages, liabilities and expenses, including reasonable costs of investigation and attorney’s fees and expenses arising out of certain legal matters as stipulated in the respective agreements with each Royalty Trust.
14. Equity
Successor Equity
Common Stock and Performance Share Units.
At December 31, 2018, the Company had 35.7 million shares of common stock, par value $0.001 per share, issued and outstanding, including 0.4 million shares of unvested restricted stock awards, and 250.0 million shares of common stock authorized. In accordance with normal practices, the Company granted additional restricted stock awards and an immaterial amount of performance share units in the third quarter of 2018.
Warrants.
The Company has issued approximately 4.6 million Series A warrants and 2.0 million Series B warrants to certain holders of general unsecured claims as defined in the Plan. These warrants are exercisable until October 4, 2022 for one share of common stock per warrant at initial exercise prices of $41.34 and $42.03 per share, respectively, subject to adjustments pursuant to the terms of the warrants. The warrants contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions.
Poison Pill.
On November 26, 2017, we entered into the Poison Pill. At our 2018 annual meeting in June 2018, the Poison Pill was terminated.
Shares Withheld for Taxes.
The following table shows the number of shares withheld for taxes and the associated value of those shares (in thousands). These shares were accounted for as treasury stock when withheld, and then immediately retired.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Period from October 2, 2016 through December 31, 2016
|
Number of shares withheld for taxes
|
|
495
|
|
349
|
|
5
|
Value of shares withheld for taxes
|
|
$
|
7,420
|
|
$
|
6,730
|
|
$
|
110
|
Predecessor Equity
Preferred Stock Dividends.
Prior to the Chapter 11 petition filings, dividends on the Company’s 8.5% and 7.0% convertible perpetual preferred stock could be paid in cash or with shares of the Company’s common stock at the Company’s election.
The Company suspended payment of the cumulative dividend on its 7.0% convertible perpetual preferred stock during the third quarter of 2015 and
suspended the semi-annual dividend on its 8.5% convertible perpetual preferred stock prior to the February 2016 semi-annual dividend payment date
. The Company ceased accruing dividends on its 8.5% and 7.0% convertible perpetual preferred stock as of May 16, 2016, in conjunction with the Chapter 11 petition filings.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Preferred stock dividend accruals in arrears prior to the Emergence Date for the Predecessor Company’s 8.5% and 7.0% convertible perpetual preferred stock were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Period from January 1, 2016 through October 1, 2016
|
8.5% Convertible perpetual preferred stock
|
|
|
Dividends in arrears
|
|
$
|
11,262
|
7.0% Convertible perpetual preferred stock
|
|
|
Dividends in arrears
|
|
$
|
21,000
|
Paid and unpaid dividends included in the calculation of income available to the Company’s common stockholders and the Company’s basic earnings per share calculation for the Predecessor 2016 Period are presented in the accompanying consolidated statements of operations. Preferred stock dividends in arrears were eliminated on the Emergence Date with no recovery paid to holders.
See Note 21 for discussion of the Company’s (loss) earnings per share calculation.
15. Share-Based Compensation
As discussed in Note 1, the Predecessor Company’s common stock was canceled and the Successor Company issued new Common Stock on the Emergence Date. Accordingly, the Predecessor Company's then existing share-based compensation awards were also canceled, which resulted in the recognition of $5.9 million in previously unamortized expense related to these awards on the date of cancellation. Share based compensation for the Predecessor and Successor periods are not comparable.
Successor Share-Based Compensation
Omnibus Incentive Plan.
The Omnibus Incentive Plan became effective on the Emergence Date after the cancellation of the Predecessor Company’s share-based compensation awards. The Omnibus Incentive Plan authorizes the issuance of up to 4.6 million shares of SandRidge Common Stock.
Persons eligible to receive awards under the Omnibus Incentive Plan include non-employee directors of the Company, employees of the Company or any of its affiliates, and certain consultants and advisors to the Company or any of its affiliates. The types of awards that may be granted under the Omnibus Incentive Plan include stock options, restricted stock, performance awards and other forms of awards granted or denominated in shares of Common Stock, as well as certain cash-based awards. At December 31, 2018, the Company had restricted stock awards and an immaterial amount of performance share units outstanding under the Omnibus Incentive Plan. Forfeitures for these awards are recognized as they occur.
Restricted Stock Awards.
The Successor Company’s restricted stock awards are equity-classified awards and are valued based upon the market value of the Company’s Common Stock on the date of grant. Vesting for certain restricted stock awards was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018. The majority of the remaining restricted stock awards vested in June 2018 as a result of the accelerated vesting event related to the change in the composition of the Board resulting from the 2018 annual meeting discussed in Note 18. The Company granted additional restricted stock awards in the second half of 2018. Outstanding restricted shares will generally vest over either a one-year period or three-year period.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The following table presents a summary of the Successor Company’s unvested restricted stock awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Shares
|
|
Weighted-
Average Grant
Date Fair Value
|
|
(In thousands)
|
|
|
Unvested restricted shares outstanding at October 1, 2016
|
—
|
|
$
|
—
|
Granted
|
1,448
|
|
$
|
24.32
|
Vested
|
(14)
|
|
$
|
24.32
|
Forfeited / Canceled
|
(27)
|
|
$
|
24.32
|
Unvested restricted shares outstanding at December 31, 2016
|
1,407
|
|
$
|
24.32
|
Granted
|
671
|
|
$
|
19.97
|
Vested
|
(827)
|
|
$
|
23.23
|
Forfeited / Canceled
|
(146)
|
|
$
|
23.52
|
Unvested restricted shares outstanding at December 31, 2017
|
1,105
|
|
$
|
22.62
|
Granted
|
370
|
|
$
|
16.00
|
Vested
|
(1,066)
|
|
$
|
22.63
|
Forfeited / Canceled
|
(44)
|
|
$
|
21.04
|
Unvested restricted shares outstanding at December 31, 2018
|
365
|
|
$
|
16.07
|
As of December 31, 2018, the Successor Company’s unrecognized compensation cost related to unvested restricted stock awards was $4.7 million. The remaining weighted-average contractual period over which this compensation cost may be recognized is 2.2 years. The aggregate intrinsic value of restricted stock that vested during 2018 was approximately $16.0 million based on the stock price at the time of vesting.
Performance Share Units.
In February 2017, the Company granted equity-classified awards in the form of performance share units. The vesting for certain performance share units was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018. All remaining units vested in June 2018 as a result of the accelerated vesting as discussed in Note 18 and were settled in shares of the Company's common stock with one share of common stock being issued per performance share unit. In September 2018, the Company granted an immaterial amount of additional performance share units. The following table presents a summary of the Company's performance share units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Units
|
|
Fair Value per Unit at December 31, 2018
|
|
|
(In thousands)
|
|
|
Unvested performance share units outstanding at December 31, 2016
|
|
—
|
|
|
Granted
|
|
199
|
|
|
Vested
|
|
—
|
|
|
Forfeited / Canceled
|
|
(16)
|
|
|
Unvested performance share units outstanding at December 31, 2017
|
|
183
|
|
|
Granted
|
|
111
|
|
|
Vested
|
|
(177)
|
|
|
Forfeited / Canceled
|
|
(6)
|
|
|
Unvested performance share units outstanding at December 31, 2018
|
|
111
|
|
$
|
20.41
|
The aggregate intrinsic value of performance share units that vested during the year ended December 31, 2018 was approximately $2.7 million based on the stock price at the time of vesting.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Successor Incentive-Based Compensation
Performance Units.
In October 2016, the Company granted liability-classified awards in the form of performance units. The vesting for certain performance units was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018. All remaining units vested in June 2018 as a result of the accelerated vesting as discussed in Note 18 and were paid at the issuance value of $100 each. The value for previous vestings was determined by annual scorecard results. The following table presents a summary of the Company's performance units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Units
|
|
Fair Value per Unit at December 31, 2018
|
|
|
(In thousands)
|
|
|
Unvested performance units outstanding at October 1, 2016
|
|
—
|
|
|
Granted
|
|
97
|
|
|
Vested
|
|
(1)
|
|
|
Forfeited / Canceled
|
|
(9)
|
|
|
Unvested performance units outstanding at December 31, 2016
|
|
87
|
|
|
Granted
|
|
—
|
|
|
Vested
|
|
(32)
|
|
|
Forfeited / Canceled
|
|
(6)
|
|
|
Unvested performance units outstanding at December 31, 2017
|
|
49
|
|
|
Granted
|
|
—
|
|
|
Vested
|
|
(48)
|
|
|
Forfeited / Canceled
|
|
(1)
|
|
|
Unvested performance units outstanding at December 31, 2018
|
|
—
|
|
—
|
The aggregate intrinsic value of performance units that vested during the year ended December 31, 2018 was approximately $4.8 million.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The following tables summarize the Successor Company's share and incentive-based compensation for the years ended December 31, 2018 and 2017, and the Successor 2016 Period (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Compensation Expense(1)
|
|
Executive Terminations(2)
|
|
Reduction in Force(2)
|
|
Accelerated Vesting(3)
|
|
Total
|
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
Equity-classified awards:
|
|
|
|
|
|
|
|
|
|
|
Restricted stock awards
|
|
$
|
4,735
|
|
$
|
8,140
|
|
$
|
3,777
|
|
$
|
5,181
|
|
$
|
21,833
|
Performance share units
|
|
619
|
|
1,056
|
|
158
|
|
610
|
|
2,443
|
Total share-based compensation expense
|
|
5,354
|
|
9,196
|
|
3,935
|
|
5,791
|
|
24,276
|
Liability-classified awards:
|
|
|
|
|
|
|
|
|
|
|
Performance units
|
|
756
|
|
2,151
|
|
558
|
|
1,309
|
|
4,774
|
Total share and incentive-based compensation expense
|
|
6,110
|
|
11,347
|
|
4,493
|
|
7,100
|
|
29,050
|
Less: Capitalized compensation expense
|
|
(482)
|
|
—
|
|
—
|
|
(555)
|
|
(1,037)
|
Share and incentive-based compensation expense, net
|
|
$
|
5,628
|
|
$
|
11,347
|
|
$
|
4,493
|
|
$
|
6,545
|
|
$
|
28,013
|
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
Equity-classified awards:
|
|
|
|
|
|
|
|
|
|
|
Restricted stock awards
|
|
$
|
14,731
|
|
$
|
1,825
|
|
$
|
—
|
|
$
|
—
|
|
$
|
16,556
|
Performance share units
|
|
1,356
|
|
—
|
|
—
|
|
—
|
|
1,356
|
Total share-based compensation expense
|
|
16,087
|
|
1,825
|
|
—
|
|
—
|
|
17,912
|
Liability-classified awards:
|
|
|
|
|
|
|
|
|
|
|
Performance units
|
|
2,574
|
|
—
|
|
—
|
|
—
|
|
2,574
|
Total share and incentive-based compensation expense
|
|
18,661
|
|
1,825
|
|
—
|
|
—
|
|
20,486
|
Less: Capitalized compensation expense
|
|
(2,521)
|
|
—
|
|
—
|
|
—
|
|
(2,521)
|
Share and incentive-based compensation expense, net
|
|
$
|
16,140
|
|
$
|
1,825
|
|
$
|
—
|
|
$
|
—
|
|
$
|
17,965
|
Period from October 2, 2016 through December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
Equity-classified awards:
|
|
|
|
|
|
|
|
|
|
|
Restricted stock awards
|
|
$
|
2,296
|
|
$
|
—
|
|
$
|
4,285
|
|
$
|
—
|
|
$
|
6,581
|
|
|
|
|
|
|
|
|
|
|
|
Total share-based compensation expense
|
|
2,296
|
|
—
|
|
4,285
|
|
—
|
|
6,581
|
Liability-classified awards:
|
|
|
|
|
|
|
|
|
|
|
Performance units
|
|
528
|
|
—
|
|
737
|
|
—
|
|
1,265
|
Total share and incentive-based compensation expense
|
|
2,824
|
|
—
|
|
5,022
|
|
—
|
|
7,846
|
Less: Capitalized compensation expense
|
|
(407)
|
|
—
|
|
—
|
|
—
|
|
(407)
|
Share and incentive-based compensation expense, net
|
|
$
|
2,417
|
|
$
|
—
|
|
$
|
5,022
|
|
$
|
—
|
|
$
|
7,439
|
____________________
1.
Recorded in general and administrative expense in the accompanying consolidated statements of operations.
2.
Recorded in employee termination benefits in the accompanying consolidated statements of operations.
3.
Recorded in accelerated vesting
of employment compensation in the accompanying consolidated statements of operations.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Predecessor Share-Based Compensation
Restricted Common Stock Awards.
The Predecessor Company’s restricted common stock awards generally vested over a four-year period, subject to certain conditions, and were valued based upon the market value of the common stock on the date of grant. The following table presents a summary of the Predecessor Company’s unvested restricted stock awards.
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Shares
|
|
Weighted-
Average Grant
Date Fair Value
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested restricted shares outstanding at December 31, 2015
|
5,626
|
|
$
|
4.85
|
Granted
|
—
|
|
$
|
—
|
Vested
|
(3,034)
|
|
$
|
5.34
|
Forfeited / Canceled
|
(2,592)
|
|
$
|
4.31
|
Predecessor ending unvested restricted shares at October 1, 2016
|
—
|
|
$
|
—
|
The Predecessor Company issued share-based compensation awards including restricted common stock awards, restricted stock units, performance units and performance share units under the 2009 Plan. Total share-based compensation expense was measured using the grant date fair value for equity-classified awards and using the fair value at period end for liability-classified awards. The Predecessor Company recognized total share-based compensation expense of $11.2 million, of which $1.7 million was capitalized, for the Predecessor 2016 Period. Share-based compensation expense for the Predecessor 2016 Period includes $5.4 million for the accelerated vesting of 1.3 million restricted common stock awards related to the Predecessor Company’s reduction in workforce during the first quarter of 2016. There was no significant activity related to the Predecessor Company’s outstanding unvested restricted stock units, performance units and performance share units during the Predecessor 2016 Period.
16. Incentive and Deferred Compensation Plans
Annual Incentive Plan.
The Annual Incentive Plan ("AIP") incorporates quantitative performance measures, strategic qualitative goals and competitive target award levels for management and employees for the 2018 and 2017 performance years. Potential payout percentages ranged from 0% to 200% of specified target levels based on actual performance. Payment for the 2018 performance year will be made in the first quarter of 2019 based on actual performance as determined by the Board of Directors relative
to the targets specified in the plan. As of December 31, 2018, the Company had accrued approximately $6.6 million for the 2018 AIP. Payment of $8.7 million was made in the first quarter of 2018 for the 2017 performance year.
Performance Incentive Plan.
In January 2016, the Company implemented a performance incentive plan which included long-term incentive awards, and provided for quarterly cash payments at a target percentage to participants based upon corporate performance goals with aggregate annual payout opportunity ranging from 0% to 200%. The first three quarterly cash payments were limited to no greater than target amounts with a cash make up payment in the first quarter of 2017 for actual performance based on the Company’s annual results. Under this plan, the Predecessor Company paid out approximately $17.8 million during the first two quarters of 2016 and the Successor Company paid out approximately $7.1 million during the fourth quarter of 2016 and approximately $15.8 million during the first quarter of 2017.
401(k) Plan.
The Company maintains a 401(k) retirement plan for its employees. Under this plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by IRS. For the years ended December 31, 2018, and 2017, the Successor 2016 Period and the Predecessor 2016 Period, the Company made matching contributions to the plan equal to 100% on the first 10% of employee deferred wages, excluding incentive compensation, totaling $2.8 million, $3.6 million,
$0.9 million and $4.9 million, respectively. The decrease in contributions is due primarily to reductions in force that occurred in 2017 and 2018.
Participants in the plan are immediately 100% vested in the discretionary employee contributions and related earnings on those contributions. The Company's matching contributions and related earnings vest based on years of service, with full vesting occurring on the fourth anniversary of employment.
Deferred Compensation Plans.
The Company maintained a non-qualified deferred compensation plan that allowed eligible highly compensated employees to elect to defer income exceeding the IRS annual limitations on qualified 401(k) retirement plans through December 31, 2016. The Company made insignificant matching contributions on non-qualified contributions for the Successor 2016 Period and the Predecessor 2016 Period. On December 31, 2016, the Successor Company began the process of terminating the non-qualified deferred compensation plan and no employee or employer contributions were made to the plan after that date. In accordance with the plan termination procedures, the $5.1 million of remaining assets
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
in the plan as of December 31, 2017, were fully distributed to participating employees during the first quarter of 2018. These assets were included in other current assets in the consolidated balance sheet at December 31, 2017.
17. Revenues
The Company adopted the new revenue standard on January 1, 2018, using the modified retrospective method for all contracts outstanding on that date. Adoption of the new revenue standard had no impact on the Company’s consolidated balance sheet, results of operations, equity or cash flows as of the adoption date, and the Company does not expect any further material impact to its consolidated financial statements on an ongoing basis as a result of adopting the new revenue standard. The Company has included the disclosures required by the new revenue standard below.
The following table disaggregates the Company’s revenue by source for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
Period from October 2, 2016 through December 31,
|
|
|
Period from January 1, 2016 through October 1,
|
|
|
2018
|
|
2017
|
|
2016
|
|
|
2016
|
Oil
|
|
$
|
214,651
|
|
$
|
202,539
|
|
$
|
57,093
|
|
|
$
|
159,023
|
NGL
|
|
67,111
|
|
61,322
|
|
14,756
|
|
|
42,541
|
Natural gas
|
|
66,964
|
|
92,349
|
|
26,458
|
|
|
78,407
|
Other
|
|
669
|
|
1,089
|
|
149
|
|
|
13,838
|
Total revenues
|
|
$
|
349,395
|
|
$
|
357,299
|
|
$
|
98,456
|
|
|
$
|
293,809
|
Oil, natural gas and NGL revenues.
A majority of the Company’s revenues come from sales of oil, natural gas and NGLs and are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck. As the Company’s customers obtain control of the production prior to selling it to other end customers, the Company presents its revenues on a net basis, rather than on a gross basis.
Pricing for the Company’s oil, natural gas and NGL contracts is variable and is based on volumes sold multiplied by either an index price, net of deductions, or a percentage of the sales price obtained by the customer, which is also based on index prices. The transaction price is allocated on a pro-rata basis to each unit of oil, natural gas or NGL sold based on the terms of the contract. Oil, natural gas and NGL revenues are also recorded net of royalties, discounts and allowances, and transportation costs, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from revenues and are included in production tax expense in the consolidated statements of operations.
Revenues Receivable.
The Company records an asset in accounts receivable, net on its consolidated balance sheet for revenues receivable from contracts with customers at the end of each period. Pricing for revenues receivable is estimated using current month crude oil, natural gas and NGL prices, net of deductions. Revenues receivable are typically collected the month after the Company delivers the related production to its customers. As of December 31, 2018, 2017 and 2016, the Company had revenues receivable of $31.8 million, $35.3 million and $42.6 million respectively, and did not record any bad debt expense on revenues receivable during the year ended December 31, 2018.
Practical expedients and exemptions.
The Company elected not to retrospectively restate contracts that were modified prior to January 1, 2017, and assumed that the contract terms in place at January 1, 2018 were in place from the inception of the contract.
Most of the Company's contracts are short-term in nature with a contract term of one year or less. The Company generally expenses certain insignificant costs when incurred rather than recognizing them as an asset because the amortization period would have been one year or less. Additionally, the Company does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less, and (ii) contracts for which revenue is recognized at the amount to which the Company has the right to invoice for services performed. Payment terms are typically within 30 days of control being transferred.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Currently, the Company’s existing contracts do not contain financing components, but the Company has elected the practical expedient that allows financing components to be ignored if the difference between the performance and payment is less than one year for any future contracts that may contain financing components.
18. Proxy Contest
In the second quarter of 2018, the Company received notification from Carl C. Icahn and certain affiliated entities (together, "Icahn"), that they intended to nominate a full slate of candidates for election to the Board at the 2018 annual meeting that was held on June 19, 2018. The Company and Icahn, together with certain of their Board nominees, each entered into a settlement agreement which expanded the size of the Board to eight directors. Previous directors Sylvia K. Barnes, David J. Kornder and William M. Griffin, Jr. were re-elected, and Bob G. Alexander, Jonathan Christodoro, Jonathan Frates, John J. "Jack" Lipinski and Randolph C. Read were newly elected following the certification of the voting results, which occurred on June 22, 2018. As confirmed by general counsel, the election of a majority of non-incumbent directors nominated in connection with the proxy contest would result in the accelerated vesting of certain share and incentive-based compensation awards granted to the Company's employees and directors as discussed further in Note 15.
The Company incurred legal, consulting and advisory fees related to dealing with shareholders and the proxy contest of $7.1 million for the year ended December 31, 2018.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
19. Employee Termination Benefits
The following table presents a summary of employee termination benefits for t
he years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
Share-Based Compensation (6)
|
|
Number of Shares
|
|
Total Employee Termination Benefits
|
Year Ended December 31, 2018 (Successor)
|
|
|
|
|
|
|
|
|
Executive Employee Termination Benefits(1)
|
|
$
|
11,945
|
|
$
|
9,196
|
|
554
|
|
$
|
21,141
|
Other Employee Termination Benefits(2)
|
|
7,581
|
|
3,935
|
|
209
|
|
11,516
|
|
|
$
|
19,526
|
|
$
|
13,131
|
|
763
|
|
$
|
32,657
|
Year Ended December 31, 2017 (Successor)
|
|
|
|
|
|
|
|
|
Executive Employee Termination Benefits(3)
|
|
$
|
2,500
|
|
$
|
1,825
|
|
96
|
|
$
|
4,325
|
Other Employee Termination Benefits
|
|
490
|
|
—
|
|
—
|
|
490
|
|
|
$
|
2,990
|
|
$
|
1,825
|
|
96
|
|
$
|
4,815
|
Period from October 2, 2016 through December 31, 2016 (Successor)
|
|
|
|
|
|
|
|
|
Executive Employee Termination Benefits
|
|
$
|
—
|
|
$
|
1,591
|
|
73
|
|
$
|
1,591
|
Other Employee Termination Benefits(4)
|
|
8,048
|
|
2,695
|
|
118
|
|
10,743
|
|
|
$
|
8,048
|
|
$
|
4,286
|
|
191
|
|
$
|
12,334
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from January 1, 2016 to October 1, 2016 (Predecessor)
|
|
|
|
|
|
|
|
|
Executive Employee Termination Benefits
|
|
$
|
810
|
|
$
|
1,072
|
|
299
|
|
$
|
1,882
|
Other Employee Termination Benefits(5)
|
|
12,427
|
|
4,047
|
|
941
|
|
16,474
|
|
|
$
|
13,237
|
|
$
|
5,119
|
|
1,240
|
|
$
|
18,356
|
____________________
1.
On February 8, 2018, the Company’s then current CEO, James Bennett, separated employment from the Company, and on February 22, 2018, the Company’s then current CFO, Julian Bott, also separated employment from the Company. In accordance with the terms of their respective employment agreements, the Company incurred cash severance costs and share-based compensation costs associated with the accelerated vesting of awards during the first quarter of 2018.
2.
As a result of a reduction in workforce in the first quarter of 2018, certain employees received termination benefits including cash severance and accelerated share
and incentive-based compensation vesting upon separation of service from the Company.
3.
Includes cash severance costs and share-based compensation costs associated with the accelerated vesting of awards related to the departure of the Company's former Executive Vice President of Investor Relations and Strategy, Duane Grubert.
4.
As a result of a reduction in workforce in the f
ourth quarter of 2016, certain employees received termination benefits including cash severance and accelerated share and incentive-based compensation vesting upon separation of service from the Company.
5.
As a result of a reduction in workforce in the f
irst quarter of 2016 and discontinuing all remaining drilling and oilfield services operations and the majority of all midstream and marketing services operations in the first quarter of 2016, certain employees received termination benefits including cash severance and accelerated share-based compensation vesting upon separation of service from the Company.
6.
Share-based compensation recognized in connection with the accelerated vesting of restricted stock awards and performance share units upon the departure of certain executives and the reduction in workforce in the first quarter of 2018 reflects the remaining unrecognized compensation expense associated with these awards at the date of termination. The unrecognized compensation expense was calculated using the grant date fair value for restricted stock awards and performance share units. One share of the Company’s common stock was issued per performance share unit.
See Note 15 for additional discussion of the Company’s share-based compensation awards.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
20. Income Taxes
The Company’s income tax (benefit) provision consisted of the following components (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
Current
|
|
|
|
|
|
|
|
|
Federal
|
$
|
(33)
|
|
$
|
(8,719)
|
|
$
|
—
|
|
|
$
|
—
|
State
|
(38)
|
|
(30)
|
|
9
|
|
|
11
|
|
(71)
|
|
(8,749)
|
|
9
|
|
|
11
|
Deferred
|
|
|
|
|
|
|
|
|
Federal
|
—
|
|
—
|
|
—
|
|
|
—
|
State
|
—
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
—
|
Total (benefit) provision
|
$
|
(71)
|
|
$
|
(8,749)
|
|
$
|
9
|
|
|
$
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A reconciliation of the (benefit) provision for income taxes at the statutory federal tax rate to the Company’s actual income tax (benefit) provision is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
Computed at federal statutory rate
|
$
|
(1,921)
|
|
$
|
13,409
|
|
$
|
(116,891)
|
|
|
$
|
504,283
|
State taxes, net of federal benefit
|
119
|
|
(284)
|
|
(3,696)
|
|
|
10,512
|
Non-deductible expenses
|
849
|
|
1,711
|
|
144
|
|
|
462
|
Non-deductible debt costs
|
—
|
|
—
|
|
—
|
|
|
22,694
|
Stock-based compensation
|
1,874
|
|
1,109
|
|
306
|
|
|
5,884
|
|
|
|
|
|
|
|
|
|
Discharge of debt and other reorganization related items
|
206
|
|
1,018
|
|
—
|
|
|
359,278
|
Return to provision adjustments (1)
|
(1,292)
|
|
341,681
|
|
—
|
|
|
—
|
Impact of legislative changes
|
—
|
|
243,801
|
|
—
|
|
|
—
|
Release of valuation allowance
|
—
|
|
(8,719)
|
|
—
|
|
|
—
|
Change in valuation allowance
|
132
|
|
(602,452)
|
|
120,144
|
|
|
(903,102)
|
Other
|
(38)
|
|
(23)
|
|
2
|
|
|
—
|
Total (benefit) provision
|
$
|
(71)
|
|
$
|
(8,749)
|
|
$
|
9
|
|
|
$
|
11
|
____________________
1.
The adjustment
for the period ended December 31, 2017, primarily related to the Company’s decision to file its 2016 income tax returns using an alternate method than previously estimated with respect to its Chapter 11 related transactions.
Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. The Company’s deferred tax assets have been reduced by a valuation allowance due to a determination made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. The Company continues to closely monitor and weigh all available evidence, including both positive and negative, in making its determination whether to maintain a valuation allowance. During the year ended December 31, 2017, the Company reduced the valuation allowance associated with deferred tax assets related to alternative minimum tax ("AMT") credits that became realizable as a result of a special tax election. Accordingly, the Company recorded an income tax benefit of $8.7 million in the year ended December 31, 2017. As a result of the significant weight placed on the Company’s cumulative negative earnings position, the Company continued to maintain the full valuation allowance against its remaining net deferred tax asset at December 31, 2017 and December 31, 2018.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
December 31, 2017
|
|
Deferred tax liabilities
|
|
|
|
|
Investments(1)
|
$
|
112,343
|
|
$
|
171,517
|
|
Derivative contracts
|
1,128
|
|
—
|
|
Total deferred tax liabilities
|
113,471
|
|
171,517
|
|
Deferred tax assets
|
|
|
|
|
Property, plant and equipment
|
267,865
|
|
391,273
|
|
Derivative contracts
|
—
|
|
3,131
|
|
|
|
|
|
|
Net operating loss carryforwards
|
302,190
|
|
217,259
|
|
|
|
|
|
|
Tax credits and other carryforwards
|
35,640
|
|
33,001
|
|
Asset retirement obligations
|
15,016
|
|
18,843
|
|
Other
|
3,816
|
|
8,959
|
|
Total deferred tax assets
|
624,527
|
|
672,466
|
|
Valuation allowance
|
(511,056)
|
|
(500,949)
|
|
Net deferred tax liability
|
$
|
—
|
|
$
|
—
|
|
____________________
1.
Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts.
The "Tax Cuts and Jobs Act" (the "TCJA") enacted in December 2017 includes significant changes to the taxation of business entities, most of which are effective for taxable years beginning after December 31, 2017. These changes include, among others, a permanent reduction to the corporate income tax rate from a maximum 35% to a flat 21% rate, expansion of expensing capital expenditures for a period of time, new limitations on the utilization of net operating losses ("NOLs"), and limitations on the deduction of interest expense and executive compensation. Based on our analysis of the TCJA and guidance currently available we recorded income tax expense of approximately $243.8 million in the period ended December 31, 2017, which was completely offset by a decrease in the corresponding valuation allowance. The provisional amount primarily related to the remeasurement of our gross deferred tax assets and liabilities existing at December 31, 2017 at the appropriate tax rate expected to exist at the time of their reversal. We completed our analysis of the impact of the TCJA and recorded an immaterial adjustment to income tax expense in the year ended December 31, 2018, which was completely offset by an increase in the corresponding valuation allowance.
Internal Revenue Code ("IRC") Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of IRC Section 382 on October 4, 2016 that subjected certain of the Company's tax attributes, including $1.9 billion of federal NOL carryforwards to the IRC Section 382 limitation. This limitation is expected to result in $1.6 billion of the $1.9 billion of federal NOL carryforwards expiring unused. As such, the Company’s deferred tax asset associated with NOLs and corresponding valuation allowance were reduced in the period ended December 31, 2017. The limitation did not result in a tax liability for the tax years ended December 31, 2016, December 31, 2017, or December 31, 2018. Since the October 4, 2016 ownership change, the Company has generated additional NOLs that are not currently subject to an IRC Section 382 limitation. See "Note 19 - Income Taxes" in the 2017 Form 10-K for additional discussion with respect to the impact of income tax elections associated with the Chapter 11 reorganization.
As of December 31, 2018, the Company had approximately $1.1 billion of federal NOL carryforwards, net of NOLs expected to expire unused due to the 2016 IRC Section 382 limitation. Of the $1.1 billion of federal NOL carryforwards, $0.8 billion expire during the years 2025 through 2037, while $0.3 billion do not have an expiration date. Additionally, the Company had federal tax credits in excess of $32.0 million which begin expiring in 2029.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
A reconciliation of the beginning and ending amount of the Company's unrecognized tax benefits is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
Unrecognized tax benefit at January 1
|
|
$
|
48
|
|
$
|
84
|
Changes to unrecognized tax benefits related to a prior period
|
|
—
|
|
2
|
Lapse of statute of limitations
|
|
(48)
|
|
(38)
|
Unrecognized tax benefit at December 31
|
|
$
|
—
|
|
$
|
48
|
Consistent with its policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included insignificant amounts of accrued gross interest with respect to unrecognized tax benefits in its accompanying consolidated statements of operations during the years ended December 31, 2017 and 2016, with none accrued in the year ended December 31, 2018.
The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2015 to present remain open for federal examination. Additionally, tax years 2005 through 2014 remain subject to examination for the purpose of determining the amount of federal NOL and other carryforwards. The number of years open for state tax audits varies, depending on the state, but is generally from
three
to
five
years.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
21. (Loss) Earnings per Share
As discussed in Note 1, on the Emergence Date, the Predecessor Company’s then-authorized common stock was canceled and the new Common Stock and Warrants were issued.
The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted (loss) earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (Loss) Income
|
|
Weighted Average Shares
|
|
(Loss) Earnings Per Share
|
|
(In thousands, except per share amounts)
|
|
|
|
|
Year Ended December 31, 2018 (Successor)
|
|
|
|
|
|
Basic loss per share
|
$
|
(9,075)
|
|
35,057
|
|
$
|
(0.26)
|
Effect of dilutive securities
|
|
|
|
|
|
Restricted stock awards (1)
|
—
|
|
—
|
|
|
Performance share units(1)
|
—
|
|
—
|
|
|
Warrants(1)
|
—
|
|
—
|
|
|
Diluted loss per share
|
$
|
(9,075)
|
|
35,057
|
|
$
|
(0.26)
|
Year Ended December 31, 2017 (Successor)
|
|
|
|
|
|
Basic earnings per share
|
$
|
47,062
|
|
32,442
|
|
$
|
1.45
|
Effect of dilutive securities
|
|
|
|
|
|
Restricted stock awards
|
—
|
|
221
|
|
|
Performance share units(2)
|
—
|
|
—
|
|
|
Warrants(2)
|
—
|
|
—
|
|
|
Diluted earnings per share
|
$
|
47,062
|
|
32,663
|
|
$
|
1.44
|
Period from October 2, 2016 to December 31, 2016 (Successor)
|
|
|
|
|
|
Basic loss per share
|
$
|
(333,982)
|
|
18,967
|
|
$
|
(17.61)
|
Effect of dilutive securities
|
|
|
|
|
|
Restricted stock awards(3)
|
—
|
|
—
|
|
|
Warrants(3)
|
—
|
|
—
|
|
|
Convertible Notes (4)
|
—
|
|
—
|
|
|
Diluted loss per share
|
$
|
(333,982)
|
|
18,967
|
|
$
|
(17.61)
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from January 1, 2016 to October 1, 2016 (Predecessor)
|
|
|
|
|
|
Basic earnings per share
|
$
|
1,424,476
|
|
708,928
|
|
$
|
2.01
|
Effect of dilutive securities
|
|
|
|
|
|
Restricted stock and units(5)
|
—
|
|
—
|
|
|
Diluted earnings per share
|
$
|
1,424,476
|
|
708,928
|
|
$
|
2.01
|
____________________
1.
No
incremental shares of potentially dilutive restricted stock awards, performance share units or warrants were included for the year ended December 31, 2018, as their effect was antidilutive under the treasury stock method.
2.
No
incremental shares of potentially dilutive performance share units or warrants were included for the year ended December 31, 2017, as their effect was antidilutive under the treasury stock method.
3.
No
incremental shares of potentially dilutive restricted stock awards or warrants were included for the Successor 2016 Period as their effect was antidilutive under the treasury stock method.
4.
Potential common shares related to the Convertible Notes covering
14.6 million shares for the Successor 2016 Period were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.
5.
No
incremental shares of potentially dilutive restricted stock awards were included for the Predecessor 2016 Period as their effect was antidilutive under the treasury stock method.
See Note 15 for discussion of the Company’s share-based compensation awards.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
22. Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)
The supplemental information below includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves.
Capitalized Costs Related to Oil and Natural Gas Producing Activities
The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
2018
|
|
2017
|
|
2016
|
Oil and natural gas properties
|
|
|
|
|
|
Proved
|
$
|
1,269,091
|
|
$
|
1,056,806
|
|
$
|
840,201
|
Unproved
|
60,152
|
|
100,884
|
|
74,937
|
Total oil and natural gas properties
|
1,329,243
|
|
1,157,690
|
|
915,138
|
Less accumulated depreciation, depletion and impairment
|
(580,132)
|
|
(460,431)
|
|
(353,030)
|
Net oil and natural gas properties capitalized costs
|
$
|
749,111
|
|
$
|
697,259
|
|
$
|
562,108
|
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
Acquisitions of properties
|
|
|
|
|
|
|
|
|
Proved
|
$
|
30,641
|
|
$
|
7,092
|
|
$
|
5,142
|
|
|
$
|
3,897
|
Unproved
|
4,197
|
|
91,139
|
|
5,491
|
|
|
1,899
|
Exploration
|
1,940
|
|
8,850
|
|
—
|
|
|
1,234
|
Development
|
158,361
|
|
187,264
|
|
27,429
|
|
|
149,924
|
Total cost incurred
|
$
|
195,139
|
|
$
|
294,345
|
|
$
|
38,062
|
|
|
$
|
156,954
|
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Results of Operations for Oil and Natural Gas Producing Activities
The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the impact the Company’s operations have on actual net earnings.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
Revenues
|
$
|
348,726
|
|
$
|
356,210
|
|
$
|
98,307
|
|
|
$
|
279,971
|
Expenses
|
|
|
|
|
|
|
|
|
Production costs
|
112,173
|
|
116,372
|
|
27,640
|
|
|
135,715
|
Depreciation and depletion
|
127,281
|
|
118,035
|
|
36,061
|
|
|
90,978
|
Impairment
|
—
|
|
—
|
|
319,087
|
|
|
657,392
|
Total expenses
|
239,454
|
|
234,407
|
|
382,788
|
|
|
884,085
|
Income (loss) before income taxes
|
109,272
|
|
121,803
|
|
(284,481)
|
|
|
(604,114)
|
Income tax expense (benefit) (1)
|
28,520
|
|
47,722
|
|
(112,427)
|
|
|
(229,986)
|
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)
|
$
|
80,752
|
|
$
|
74,081
|
|
$
|
(172,054)
|
|
|
$
|
(374,128)
|
____________________
1.
Income tax
expense (benefit) is hypothetical and is calculated by applying the Company’s statutory tax rate to income (loss) before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits.
Oil, Natural Gas and NGL Reserve Quantities
Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on oil, natural gas and NGL prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following:
•
the quality and quantity of available data and the engineering and geological interpretation of that data;
•
estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;
•
the accuracy of mandated economic assumptions; and
•
the judgment of the personnel preparing the estimates.
Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.
The following table represents the Company’s estimate of proved oil, natural gas and NGL reserves attributable to the Company’s net interest in oil and natural gas properties, all of which are located in the continental United States, based upon the evaluation by the Company and its independent petroleum engineers of pertinent geoscience and engineering data in accordance
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
with the SEC’s regulations. Over 90% of the Company’s proved reserves estimates have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of the Company’s senior management with professional training in petroleum engineering to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the SEC.
Cawley, Gillespie & Associates, Ryder Scott and Netherland Sewell, independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs attributable to the majority of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2018, 2017 and 2016. Cawley, Gillespie & Associates, Ryder Scott and Netherland Sewell are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Company or its properties and are not employed on a contingent basis. The remaining proved reserves were based on Company estimates.
The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.
2018 Activity.
Proved reserves decreased from 177.6 MMBoe at December 31, 2017 to 160.2 MMBoe at December 31, 2018, primarily as a result of a one-time adjustment to future workover costs in the Company's Mississippian Lime wells. As its large population of Mississippian Lime wells transition into late-life mature production, the Company has experienced increasing operating costs which have been incorporated into its 2018 reserve report. This estimate of future costs contributed to a 24.9 MMBoe decrease associated with shorter economic lives. The Company also recorded a decrease of 8.3 MMBoe attributable to well performance and a decrease of 6.6 MMBoe due to divestitures of proved reserves. These reductions were partially offset by the acquisition of 15.4 MMBoe associated with the purchase of interests in Mid-Continent wells, extensions and discoveries of 19.3 MMBoe from successful drilling in the North Park Basin and to a lesser extent the NW STACK play in the Mid-Continent, as well as recording proved undeveloped reserves at an increased well density in the North Park Basin.
2017 Activity.
During 2017, the Company recorded extensions and discoveries of 19.4 MMBoe, primarily from successful drilling in its NW STACK play in the Mid-Continent area and its North Park Basin properties, sold 1.9 MMBoe of proved reserves, and recorded upward revisions of 10.9 MMBoe, primarily as a result of significantly higher commodity prices in 2017 and minor revisions due to well performance.
2016 Activity.
During 2016, on a pro forma combined basis, the Predecessor Company and Successor Company recognized total downward revisions of prior estimates of approximately 105.4 MMBoe, predominantly from revisions of approximately 94.7 MMBoe due to well performance and 12.1 MMBoe due to a decrease in commodity prices. The negative revisions from well performance were from the Mid-Continent area and resulted from steeper than anticipated well production decline rates for Mississippian horizontal wells in areas with increased natural fracture density and that have been developed with three or more horizontal wells per section as inter-well pressure communication has had more impact on well performance than originally forecasted. Additionally, changing pressure conditions in the Company’s Mississippian wells producing with artificial lift have resulted in increased production decline rates that are now becoming more predictable on a large group of base wells as this population of wells has been producing for more than two years. Of the total performance revisions, approximately 85% were to gas and associated NGL reserves, with the revisions to gas mostly from changes made to late-life decline rates, and 15% were to oil reserves. Other decreases of reserves excluding production included the sale of WTO reserves of 24.6 MMBoe and 19.1 MMBoe of adjustment from change in accounting for Trusts. These decreases were partially offset by approximately 7.8 MMBoe of extensions due to successful drilling.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The summary below presents changes in the Company’s estimated reserves.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
NGL
|
|
Natural Gas
|
|
Total
|
|
(MBbls)
|
|
(MBbls)
|
|
(MMcf)(1)
|
|
MBoe
|
Proved developed and undeveloped reserves
|
|
|
|
|
|
|
|
As of December 31, 2015(2) - Predecessor
|
77,911
|
|
61,075
|
|
1,113,840
|
|
324,626
|
Adoption of ASU 2015-02
|
(6,971)
|
|
(3,695)
|
|
(50,508)
|
|
(19,084)
|
Revisions of previous estimates
|
(39,973)
|
|
(21,475)
|
|
(415,568)
|
|
(130,709)
|
Extensions and discoveries
|
987
|
|
472
|
|
7,955
|
|
2,785
|
Sales of reserves in place
|
(387)
|
|
—
|
|
(145,267)
|
|
(24,598)
|
Production
|
(4,315)
|
|
(3,358)
|
|
(44,124)
|
|
(15,027)
|
As of October 1, 2016 - Predecessor
|
27,252
|
|
33,019
|
|
466,328
|
|
137,992
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
23,978
|
|
1,139
|
|
915
|
|
25,270
|
Extensions and discoveries
|
2,868
|
|
448
|
|
10,309
|
|
5,034
|
Production
|
(1,214)
|
|
(999)
|
|
(12,770)
|
|
(4,341)
|
As of December 31, 2016 - Successor
|
52,884
|
|
33,607
|
|
464,782
|
|
163,955
|
Revisions of previous estimates
|
804
|
|
2,628
|
|
44,679
|
|
10,879
|
Acquisitions of new reserves
|
18
|
|
70
|
|
683
|
|
202
|
Extensions and discoveries
|
12,446
|
|
1,914
|
|
30,080
|
|
19,373
|
Sales of reserves in place
|
(204)
|
|
(529)
|
|
(7,055)
|
|
(1,909)
|
Production
|
(4,157)
|
|
(3,376)
|
|
(44,237)
|
|
(14,906)
|
As of December 31, 2017 - Successor
|
61,791
|
|
34,314
|
|
488,932
|
|
177,594
|
Revisions of previous estimates
|
(2,316)
|
|
(8,952)
|
|
(131,518)
|
|
(33,188)
|
Acquisitions of new reserves
|
2,146
|
|
4,131
|
|
54,436
|
|
15,350
|
Extensions and discoveries
|
11,148
|
|
2,320
|
|
35,185
|
|
19,332
|
Sales of reserves in place
|
(5,273)
|
|
(809)
|
|
(2,969)
|
|
(6,577)
|
Production
|
(3,477)
|
|
(2,829)
|
|
(36,175)
|
|
(12,335)
|
As of December 31, 2018 - Successor
|
64,019
|
|
28,175
|
|
407,891
|
|
160,176
|
Proved developed reserves
|
|
|
|
|
|
|
|
As of December 31, 2015 - Predecessor
|
48,639
|
|
51,089
|
|
964,617
|
|
260,498
|
As of October 1, 2016 - Predecessor
|
24,541
|
|
30,238
|
|
428,050
|
|
126,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016 - Successor
|
25,911
|
|
29,290
|
|
393,028
|
|
120,706
|
As of December 31, 2017 - Successor
|
25,845
|
|
29,922
|
|
407,988
|
|
123,765
|
As of December 31, 2018 - Successor
|
18,693
|
|
22,302
|
|
307,845
|
|
92,303
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
As of December 31, 2015 - Predecessor
|
29,272
|
|
9,986
|
|
149,223
|
|
64,129
|
As of October 1, 2016 - Predecessor
|
2,711
|
|
2,781
|
|
38,278
|
|
11,872
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016 - Successor
|
26,973
|
|
4,317
|
|
71,754
|
|
43,249
|
As of December 31, 2017 - Successor
|
35,946
|
|
4,392
|
|
80,944
|
|
53,829
|
As of December 31, 2018 - Successor
|
45,326
|
|
5,873
|
|
100,046
|
|
67,873
|
____________________
1.
Natural gas reserves are computed at
14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
2.
Includes proved reserves attributable to noncontrolling interests as shown in the table below:
|
|
|
|
|
|
|
Predecessor
|
|
December 31,
|
|
2015
|
Oil (MBbl)
|
7,004
|
NGL (MBbl)
|
3,694
|
Natural gas (MMcf)
|
50,508
|
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with ASC Topic 932, Extractive Activities—Oil and Gas, ("ASC Topic 932"). The assumptions underlying the computation of the standardized measure of discounted cash flows may be summarized as follows:
•
the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions;
•
pricing is applied based upon
SEC prices at December 31, 2018, 2017, and 2016 adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
|
|
|
|
2018
|
|
2017
|
|
2016
|
Oil (per barrel)
|
$
|
60.86
|
|
$
|
48.47
|
|
$
|
38.59
|
NGL (per barrel)
|
$
|
25.62
|
|
$
|
20.28
|
|
$
|
10.99
|
Natural gas (per Mcf)
|
$
|
1.77
|
|
$
|
1.90
|
|
$
|
1.56
|
•
future development and production costs are determined based upon actual cost at year-end;
•
the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and
•
a discount factor of 10% per year is applied annually to the future net cash flows.
The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
2018
|
|
2017
|
|
2016
|
Future cash inflows from production
|
$
|
5,339,265
|
|
$
|
4,621,615
|
|
$
|
3,136,762
|
Future production costs
|
(1,996,689)
|
|
(1,837,852)
|
|
(1,454,798)
|
Future development costs(1)
|
(1,170,113)
|
|
(966,203)
|
|
(665,516)
|
Future income tax expenses (2)
|
—
|
|
(107)
|
|
(142)
|
Undiscounted future net cash flows
|
2,172,463
|
|
1,817,453
|
|
1,016,306
|
10% annual discount
|
(1,126,860)
|
|
(1,068,159)
|
|
(577,942)
|
Standardized measure of discounted future net cash flows
|
$
|
1,045,603
|
|
$
|
749,294
|
|
$
|
438,364
|
____________________
1.
Includes abandonment costs.
2.
The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws
, including expected tax benefits to be realized from the utilization of net operating loss carryforwards.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
Beginning present value
|
$
|
749,294
|
|
$
|
438,364
|
|
$
|
392,604
|
|
|
$
|
1,314,562
|
Changes during the year
|
|
|
|
|
|
|
|
|
Adoption of ASU 2015-02
|
—
|
|
—
|
|
—
|
|
|
(224,965)
|
Revenues less production
|
(236,553)
|
|
(239,838)
|
|
(70,668)
|
|
|
(144,256)
|
Net changes in prices, production and other costs
|
316,095
|
|
347,458
|
|
35,684
|
|
|
(394,173)
|
Development costs incurred
|
80,050
|
|
35,517
|
|
7,941
|
|
|
69,080
|
Net changes in future development costs
|
(11,483)
|
|
(64,484)
|
|
(291,232)
|
|
|
436,041
|
Extensions and discoveries
|
102,961
|
|
112,556
|
|
14,986
|
|
|
12,449
|
Revisions of previous quantity estimates
|
(91,038)
|
|
26,697
|
|
308,374
|
|
|
(728,254)
|
Accretion of discount
|
70,576
|
|
37,226
|
|
9,375
|
|
|
91,337
|
Net change in income taxes
|
56
|
|
23
|
|
—
|
|
|
402
|
Purchases of reserves in-place
|
35,713
|
|
454
|
|
—
|
|
|
—
|
Sales of reserves in-place
|
(2,029)
|
|
(2,977)
|
|
—
|
|
|
(13,314)
|
Timing differences and other(1)
|
31,961
|
|
58,298
|
|
31,300
|
|
|
(26,305)
|
Net change for the year
|
296,309
|
|
310,930
|
|
45,760
|
|
|
(921,958)
|
Ending present value(2)
|
$
|
1,045,603
|
|
$
|
749,294
|
|
$
|
438,364
|
|
|
$
|
392,604
|
____________________
1.
The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.
2.
Standardized Measure w
as determined using SEC prices, and does not reflect actual prices received or current market prices.
23. Quarterly Financial Results (Unaudited)
The Company’s operating results for each quarter of 2018 and 2017 are summarized below (in thousands, except per share data).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth Quarter
|
2018
|
|
|
|
|
|
|
|
Total revenues
|
$
|
87,128
|
|
$
|
79,462
|
|
$
|
97,660
|
|
$
|
85,145
|
(Loss) income from operations(1)(2)
|
$
|
(41,967)
|
|
$
|
(33,685)
|
|
$
|
12,430
|
|
$
|
52,847
|
Net (loss) income(1)(2)
|
$
|
(40,894)
|
|
$
|
(34,074)
|
|
$
|
11,715
|
|
$
|
54,178
|
|
|
|
|
|
|
|
|
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders
|
|
|
|
|
|
|
|
Basic
|
$
|
(1.18)
|
|
$
|
(0.97)
|
|
$
|
0.33
|
|
$
|
1.53
|
Diluted
|
$
|
(1.18)
|
|
$
|
(0.97)
|
|
$
|
0.33
|
|
$
|
1.53
|
____________________
1.
Includes
loss (gain) on derivative contracts of $18.3 million, $30.1 million, $11.3 million and $(42.6) million for the first, second, third and fourth quarters, respectively.
2.
Includes employee termination benefits of
$31.6 million for the first quarter, accelerated vesting of employment compensation of $6.5 million for the second quarter, and proxy contest costs of $7.2 million for the second quarter.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
2017
|
|
|
|
|
|
|
|
Total revenues
|
$
|
98,350
|
|
$
|
84,851
|
|
$
|
80,892
|
|
$
|
93,206
|
Income (loss) from operations(1)(2)
|
$
|
50,780
|
|
$
|
23,348
|
|
$
|
(16,267)
|
|
$
|
(18,230)
|
Net income (loss)(1)(2)
|
$
|
50,808
|
|
$
|
23,499
|
|
$
|
(8,485)
|
|
$
|
(18,760)
|
|
|
|
|
|
|
|
|
Income available (loss applicable) per share to SandRidge Energy, Inc. common stockholders
|
|
|
|
|
|
|
|
Basic
|
$
|
1.90
|
|
$
|
0.69
|
|
$
|
(0.25)
|
|
$
|
(0.54)
|
Diluted
|
$
|
1.90
|
|
$
|
0.69
|
|
$
|
(0.25)
|
|
$
|
(0.54)
|
____________________
1.
Includes (gain) loss on derivative contracts of
$(34.2) million, $(23.5) million, $11.7 million and $21.9 million for the first, second, third and fourth quarters, respectively.
2.
Includes
employee termination benefits of $4.4 million for the second quarter and terminated merger costs of $8.2 million for the fourth quarter.
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)