EX-99.1

EX-99.1 2 d690513dex991.htm EX-99.1 EX-99.1

Exhibit 99.1


		NEWS RELEASE

RIVIERA RESOURCES REPORTS FIRST-QUARTER 2019 RESULTS; ENGAGES INVESTMENT BANK TO UNLOCK BLUE MOUNTAIN VALUE THROUGH STRATEGIC ALTERNATIVES; AND ANNOUNCES ATTENDANCE AT RBC CAPITAL MARKETS GLOBAL ENERGY & POWER INVESTOR CONFERENCE

HOUSTON, May 9, 2019 – Riviera Resources, Inc. (OTCQX: RVRA) (“Riviera” or the “Company”) and its wholly owned subsidiary, Blue Mountain Midstream LLC (“Blue Mountain”) announces financial and operating results for the first quarter 2019 and provides a strategic update.

The Company highlights the following accomplishments:

•

Blue Mountain engaged Tudor, Pickering, Holt & Co. to unlock unrealized value through pursuing strategic alternatives, including consolidation to achieve greater scale or potential sale

•

Blue Mountain initiated construction of water gathering facilities during the quarter and began providing water services to Roan Resources, Inc. (“Roan”) on April 1, 2019

•

Sold Arkoma Basin assets for proceeds of approximately $65 million, and signed a definitive agreement to sell its interest in certain non-operated properties located in the Hugoton Basin for a contract price of $31 million, both at a premium to PDP PV-10 value

•

Monetized approximately 23% of total helium reserves through a VPP structure at an attractive 5.16% discount rate for proceeds of approximately $82 million

•

Repurchased ~2.5 million shares for ~$34 million in the first quarter as part of the ongoing $100 million share repurchase authorization

•

Ended first quarter with a consolidated cash balance of ~$102 million and $14.5 million drawn on the Blue Mountain Credit Facility

•

Outperformed adjusted EBITDAX guidance for the first quarter

•

Generated first quarter 2019 average production, operating costs, and capital in line with guidance

•

Turned to sales during the quarter 3 NW STACK operated wells, and 2 North Louisiana wells, with strong initial results

The Company’s strategic initiatives for 2019 include:

•

Continuing to use cash on hand, free cash flow, and opportunistic asset monetizations to return capital to our shareholders

•

Continuing to grow and diversify Blue Mountain’s midstream business to best position it towards a strategic transaction

•

Focusing upstream capital on high-return projects that maintain production and delineate the highly prospective ~105,000 net acres in the Anadarko Basin while still generating significant free cash flow

David Rottino, Riviera’s President and Chief Executive Officer, commented, “I am very pleased with Riviera’s performance in the first quarter. Operationally, our base assets performed in line with guidance and our drilling program focused in the Northwest STACK and North Louisiana looks very encouraging. We remain relentlessly focused on our commitment to maximizing shareholder value through our strategy of capital discipline, returning capital to shareholders and efficiently managing our assets. We continue to believe our shares are deeply undervalued and we are committed to finding ways to monetize assets and use cash on hand to return capital to shareholders. So far this year, we sold our Arkoma basin asset, for a premium to PV-10, monetized a portion of our Helium reserves at an attractive discount rate, and announced the sale of our interests in certain non-operated assets in the Hugoton Basin. Additionally, we bought back approximately 2.5 million shares in the first quarter, making great progress on our share repurchase commitment. Finally, the Board recently approved the engagement of an investment bank to assist in the review and execution of strategic alternatives for Blue Mountain to best position it towards a value enhancing transaction.”

Key Financial Results ⁽¹⁾


	First Quarter
$ in millions	2019		2018
Average daily production (MMcfe/d)		265		401
Total oil, natural gas and NGL revenues	$	76	$	137
Income from continuing operations	$	13	$	35
Income from discontinued operations, net of income taxes	$	—	$	36
Net income	$	13	$	71
Adjusted EBITDAX (a non-GAAP financial measure) ⁽²⁾	$	29	$	40
Net cash provided by operating activities	$	38	$	51
Oil and natural gas capital	$	38	$	10
Total capital	$	61	$	67

(1)

All amounts reflect continuing operations with the exception of net income for the three months ended March 31, 2018.

(2)

Includes severance costs of approximately $0.1 million and $6 million, for the three months ended March 31, 2019 and March 31, 2018, respectively.

Strategic Update

The Board and management believe the Company is trading at a significant discount to its sum-of-the-parts net asset value. The Board recently approved the engagement of an investment bank to assist in the review and execution of strategic alternatives for Blue Mountain through a value enhancing transaction. Furthermore, the Company will continue to return capital to shareholders through free cash flow generated from efficiently managing our assets, and by opportunistically monetizing additional assets.

Continuation of Share Repurchase Plan

On August 16, 2018, the Company’s Board of Directors authorized the repurchase of up to $100 million of the Company’s outstanding shares of common stock. Through April 30, 2019, the Company repurchased an aggregate of 4,793,804 shares at an average price of $15.08 for a total cost of approximately $72 million. Approximately $28 million was available for share repurchase as of April 30, 2019 under the repurchase authorization. In April alone, the Company repurchased approximately 1.4 million shares at an average price of $14.55 for a total cost of approximately $20 million.

Opportunistic Asset Monetizations

Thus far in 2019, the Company has closed or announced three transactions that in combination will generate expected proceeds of approximately $175 million. The actual and expected proceeds from the three deals are at a premium to the PDP PV-10 value. The three transactions include the sale of the Arkoma Basin assets (closed January, 2019), the announced sale of certain non-operated properties located in the Hugoton Basin (expected to close in Q2 2019), and the monetization of a portion of the Company’s helium reserves in the Hugoton Basin utilizing a VPP structure (closed March, 2019).

Under the VPP structure, Riviera conveyed a term overriding royalty interest in helium from certain of its Hugoton wells (the “VPP Interests”) to Mayzure, LLC (“Mayzure”), a wholly owned subsidiary of Riviera, which funded the purchase with the net proceeds of its issuance of 5.16% senior secured notes (the “Notes”). Riviera expects Mayzure to fully satisfy the principal and interests obligations under the Notes with the monthly proceeds of the VPP Interests in the third quarter of 2026. As projected, over the term of the VPP Interests, Riviera expects to monetize approximately 23% of its total helium reserves for $82 million. In 2019, Riviera forecasts the value of the helium production conveyed to Mayzure and applied to the Notes will be approximately $14.6 million, of which approximately $11 million is expected to be paid in 2019.

First Quarter 2019 Activity – Upstream Assets

Riviera’s production for the first quarter averaged approximately 265 MMcfe/d, in line with our guidance range. Despite cold weather and unexpected downtime in the Mid-Continent and Hugoton basins, the Company was able to meet expectations. The low annual decline of approximately 10% and diverse asset base help the predictability of our upstream business. Additionally, we believe the development opportunities through our NW STACK, East Texas, and North Louisiana acreage positions provide significant upside.

With respect to costs, the Company performed in line with expectations in the first quarter. Upstream capital expenditures were approximately $39 million compared to guidance of $40 million. Adjusted G&A expenses were approximately $9 million, 4% below the mid-point of our guidance range for the quarter. Operating expenses for the first quarter were in-line with guidance at approximately $49 million.

Northwest STACK / North Louisiana Operated Drilling Program

Riviera’s operated NW STACK drilling program is progressing on schedule with the Company turning to production 3 wells in the first quarter and 2 additional wells thus far in the second quarter. Early results are encouraging. The average IP15 rate of the first 4 wells is approximately 610 boepd with 43% oil and 65% liquids. All of these wells are single mile laterals with a target capital cost of $5.0 million to $5.3 million, which is expected to generate a 30% to 40% IRR.

The Company also completed a 2 well pad in North Louisiana late in the first quarter. The initial production of these wells is very strong with a choke restricted 2 well average IP30 of approximately 20 MMcfe/d. The expected IRR of these wells is over 100%.

Blue Mountain Business Update

On average for the first quarter of 2019, natural gas throughput was 117 MMcf/d and NGLs produced were approximately 8,700 bpd, compared with 61 MMcf/d and 2,290 bpd for the first quarter 2018. Natural gas throughput volumes for the first quarter of 2019 were lower compared to the fourth quarter of 2018 throughput of 132 MMcf/d as our primary customer re-evaluated their drilling plans. Throughput volumes are expected to increase during the remainder of 2019 as Roan has announced plans to increase average annual production by 30% over 2018.

Management continues to diversify and extend Blue Mountain’s midstream business to best position it for its eventual separation as a standalone entity or for another transaction that maximizes shareholder value.

During the first quarter, Blue Mountain announced its entrance into the produced water management business with the execution of an agreement with Roan to completely handle all their water management needs in the dedicated acreage footprint, including produced water gathering, treating, transportation and disposal. Blue Mountain began providing these services on April 1, 2019.

In addition, Blue Mountain finalized an agreement with a new third-party to provide natural gas gathering and processing services on its Merge system. The agreement carries a long-term acreage dedication with primarily fee-based revenues and the potential for incremental volumes as drilling activity advances within the dedicated acreage footprint. Management believes the area has significant upside and is in active discussions with several third-party producers to attract incremental natural gas and produced water volumes to its core Merge platform.

Blue Mountain’s adjusted EBITDA for the first quarter of 2019 was flat compared to the fourth quarter of 2018, on approximately 9% decrease in average natural gas throughput over the prior quarter. Adjusted EBITDA remained flat due to tightening of the spread between Conway and Mont Belvieu NGL pricing. Elimination of the basis exposure would have added approximately $2 million to Blue Mountain’s margin in the first quarter of 2019. Management has hedged a material portion of its exposure to the NGL pricing differentials at Conway and Mont Belvieu for 2019 and expects to eliminate all basis dislocation by the first quarter of 2020 when ONEOK’s Arbuckle II Pipeline is completed.

Capital for the first quarter was $21 million, compared with $57 million for the first quarter of 2018. The majority of capital was invested in new well connects in the Merge and construction of water gathering pipelines.

“I’m pleased with Blue Mountain’s performance over the quarter as we made significant strides to diversify our revenue stream going forward. With Roan’s projected volume ramp during the second half of 2019, our water business becoming established moving to our piped system, and other growth prospects in development; I’m excited about our continued evolution becoming a top tier midstream enterprise,” commented Greg Harper, President and CEO of Blue Mountain.

Balance Sheet and Liquidity

Riviera and Blue Mountain have established separate credit facilities. As of the spring redetermination, there were no borrowings outstanding on Riviera’s revolving credit facility, and borrowing commitments of up to $250 million with available borrowing capacity of approximately $216 million, inclusive of outstanding letters of credit. Riviera’s borrowing base was reduced to $245 million due to the expected sale of its interest in certain non-operated properties located in the Hugoton Basin.

As of March 31, 2019, Blue Mountain had $14.5 million drawn on its revolving credit facility, and borrowing commitments of up to $200 million with available borrowing capacity of approximately $174 million, including outstanding letters of credit, and subject to covenant restrictions in the Blue Mountain Credit Facility.

First Quarter Actuals

Below is a summary of the Company’s consolidated first quarter results.


	Q1 2019 Actuals			Q1 2019 Actuals			Q1 2019 Actuals
	Upstream			Blue Mountain			Consolidated
Net Production (MMcfe/d)		265						265
Natural gas (MMcf/d)		216						216
Oil (Bbls/d)		1,196						1,196
NGL (Bbls/d)		6,946						6,946

Other revenues, net (in thousands)⁽¹⁾	$	11,238	⁽²⁾	$	11,010	⁽³⁾	$	22,248	⁽⁴⁾
Helium revenues	$	5,675	⁽⁵⁾				$	5,675	⁽⁵⁾
Jayhawk / Other	$	5,563					$	5,563
Blue Mountain				$	11,010	⁽³⁾	$	11,010	⁽³⁾

Costs (in thousands)	$	48,827		$	675		$	49,502
Lease operating expenses	$	24,052					$	24,052
Transportation expenses	$	19,150					$	19,150
Taxes, other than income taxes	$	5,625		$	675		$	6,300

Adjusted general and administrative expenses ⁽⁶⁾	$	9,105	⁽⁷⁾	$	3,639	⁽⁸⁾	$	12,744	⁽⁹⁾

Targets (in thousands)
Adjusted EBITDAX	$	22,020	⁽¹⁰⁾	$	6,881		$	28,901	⁽¹⁰⁾
Interest expense ⁽¹¹⁾	$	181		$	134		$	316
Oil and natural gas capital	$	37,646					$	37,646
Total capital	$	39,370		$	21,316		$	60,686

(1)	Includes other revenues and margin on marketing activities

(2)	Includes other revenues of approximately $6.0 million, plus marketing revenues of approximately $25.0 million, less marketing expenses of approximately $19.8 million for the three months ended March 31, 2019

(3)	Includes marketing revenues of approximately $42.3 million, less adjusted marketing expenses of approximately $31.3 million. Adjusted marketing expenses is a non-GAAP measure that excludes share-based compensation expenses of approximately $0.1 million

(4)

Includes other revenues of approximately $6.0 million, plus marketing revenues of approximately $67.3 million, less adjusted marketing expenses of approximately $51.1 million. Adjusted marketing expenses is a non-GAAP measure that excludes share-based compensation expenses of approximately $0.1 million and losses on derivatives of approximately $2.2 million

(5)	Includes helium revenues from the VPP Interests of approximately $3.7 million

(6)	Adjusted general and administrative expenses is a non-GAAP measure that excludes share-based compensation expenses and severance expenses presented for the purpose of comparing to guidance

(7)	For the three months ended March 31, 2019 represents general and administrative expenses of approximately $11.4 million, excluding share-based compensation expenses of approximately $2.2 million and non-recurring severance expenses of approximately $0.1 million

(8)	For the three months ended March 31, 2019 represents general and administrative expenses of approximately $7.6 million, excluding share-based compensation expenses of approximately $4.0 million

(9)	For the three months ended March 31, 2019 represents general and administrative expenses of approximately $19.0 million, excluding share-based compensation expenses of approximately $6.2 million and non-recurring severance expenses of approximately $0.1 million

(10)	Includes a reduction to Adjusted EBITDAX for certain non-recurring severance expenses of approximately $0.1 million, and provision for legal matters of $1.1 million

(11)	Excludes non cash amortization

Upstream Segment - First Quarter Actuals versus Guidance

The comparison to guidance below is for the upstream assets only. The Company did not provide first quarter 2019 guidance for Blue Mountain. The 2019 upstream actuals and guidance include the Arkoma Basin divestiture that closed on January 17, 2019, the Helium VPP transaction that closed in March 2019, and the sale of non-operated properties in the Hugoton Basin that is expected to close in the second quarter of 2019.


	Q1 2019 Actuals			Q1 2019 Guidance
Net Production (MMcfe/d)		265		252 – 281
Natural gas (MMcf/d)		216		205 – 230
Oil (Bbls/d)		1,196		1,150 – 1,300
NGL (Bbls/d)		6,946		6,600 – 7,300

Other revenues, net (in thousands)⁽¹⁾	$	11,238	⁽²⁾	$ 8,000 - $ 10,000
Helium revenues		5,675	⁽³⁾
Jayhawk / Other		5,563

Costs (in thousands)	$	48,827		$ 46,000 – $ 52,000
Lease operating expenses	$	24,052		$ 23,000 – $ 25,000
Transportation expenses	$	19,150		$ 18,000 – $ 20,000
Taxes, other than income taxes	$	5,625		$ 5,000 – $ 7,000

Adjusted general and administrative expenses ⁽⁴⁾	$	9,105	⁽⁵⁾	$ 9,000 – $ 10,000

Targets (Mid-Point) (in thousands)
Adjusted EBITDAX	$	22,020	⁽⁶⁾	$ 21,000
Interest expense ⁽⁷⁾	$	181
Oil and natural gas capital	$	37,646		$ 38,000
Total capital	$	39,370		$ 40,000

(1)	Includes other revenues and margin on marketing activities

(2)	Includes other revenues of approximately $6.0 million, plus marketing revenues of approximately $25.0 million, less marketing expenses of approximately $19.8 million for the three months ended March 31, 2019

(3)	Includes helium revenues from the VPP Interests of approximately $3.7 million

(4)	Adjusted general and administrative expenses is a non-GAAP measure that excludes share-based compensation expenses and severance expenses presented for the purpose of comparing to guidance

(5)	For the three months ended March 31, 2019 represents general and administrative expenses of approximately $11.4 million, excluding share-based compensation expenses of approximately $2.2 million and non-recurring severance expenses of approximately $0.1 million

(6)	Includes a reduction to Adjusted EBITDAX for certain non-recurring severance expenses of approximately $0.1 million, and provision for legal matters of $1.1 million

(7)	Excludes non cash amortization

Upstream Segment - Second Quarter and Full Year 2019 Guidance

The guidance below is for the upstream assets only. Guidance estimates have been adjusted for the pending sale of non-operated properties located in the Hugoton Basin that is expected to close in the second quarter. 2019 guidance estimates include the adjusted EBITDAX from the Helium VPP transaction that closed in March, 2019. The 2019 guidance also includes production, capital, and adjusted EBITDAX before closing for the Arkoma Basin divestiture that closed January 17, 2019, and the sale of non-operated properties located in the Hugoton Basin that is expected to close in the second quarter.


	Q2 2019E	FY 2019E
Net Production (MMcfe/d)	255 – 285	248 – 274
Natural gas (MMcf/d)	210 – 235	203 – 225
Oil (Bbls/d)	1,600 – 1,850	1,500 – 1,800
NGL (Bbls/d)	5,900 – 6,500	5,900 – 6,500

Other revenues, net (in thousands)⁽¹⁾	$ 5,500 - $ 7,500	$ 31,000 – $ 34,000
Helium revenues	$ 4,500 – $ 5,500⁽²⁾	$ 21,000 – $ 23,000⁽³⁾
Jayhawk / Other	$ 1,000 – $ 2,000	$ 10,000 – $ 11,000

Costs (in thousands)	$ 45,000 – $ 50,000	$ 177,000 – $ 195,000
Lease operating expenses	$ 23,000 – $ 25,000	$ 88,000 – $ 96,000
Transportation expenses	$ 17,000 – $ 18,000	$ 67,000 – $ 75,000
Taxes, other than income taxes	$ 5,000 – $ 7,000	$ 22,000 – $ 24,000

Adjusted general and administrative expenses ⁽⁴⁾	$ 7,500 – $ 9,000	$ 30,000 – $ 35,000

Costs per Mcfe (Mid-Point)	$ 1.93	$ 1.95
Lease operating expenses	$ 0.98	$ 0.97
Transportation expenses	$ 0.71	$ 0.75
Taxes, other than income taxes	$ 0.24	$ 0.24

Targets (Mid-Point) (in thousands)
Adjusted EBITDAX	$ 23,000	$ 95,000
VPP Notes interest expense payments	$ 1,000	$ 3,000
VPP Notes principal payments	$ 3,000	$ 8,000
Capital expenditures	$ 19,000	$ 68,000

Weighted Average NYMEX Differentials
Natural gas (MMBtu)	($ 0.50) – ($ 0.30)	($ 0.45) – ($ 0.20)
Oil (Bbl)	($ 3.00) – ($ 2.20)	($ 3.00) – ($ 2.00)
NGL price as a % of crude oil price	34% – 38%	36% – 40%


	Apr 19		May 19		Jun 19		2019E
Unhedged Commodity Price Assumptions
Natural gas (MMBtu)	$	2.71	$	2.49	$	2.54	$	2.78
Oil (Bbl)	$	64.00	$	64.00	$	64.07	$	61.67
NGL (Bbl)	$	22.91	$	22.98	$	22.99	$	23.65

(1)

Includes other revenues and margin on marketing activities for Upstream assets, only

(2)

Includes helium revenues from the VPP Interests of approximately $3.7 million

(3)

Includes helium revenues from the VPP Interests of approximately $14.6 million

(4)

Excludes share-based compensation expenses

Hedging Update

Riviera Upstream Hedges


	2019		2020
*Natural Gas*	Volume (MMMBtu/d)	Average Price (per MMBtu)	Volume (MMMBtu/d)	Average Price (per MMBtu)
Swaps	141	$2.88	30	$2.82
Collars	20	$2.75 - $3.00	—	$—

*Oil*	Volume (Bbls/d)	Average Price (per Bbl)	Volume (Bbls/d)	Average Price (per Bbl)
Swaps	1,000	$64.32	500	$64.63

*Natural Gas Basis Differential positions*	Volume (MMMBtu/d)	Average Price (per MMBtu)	Volume (MMMBtu/d)	Average Price (per MMBtu)
PEPL Basis Swaps	70	($0.64)	20	($ 0.45)
MichCon Basis Swaps	20	($0.19)	10	($0.19)
NWPL Basis Swaps	10	($0.61)	—	$—

Blue Mountain Hedges


	2019
*Natural Gas*	Volume (MMMBtu/d)	Average Price (per MMBtu)
Swaps	15	$2.81

*Oil*	Volume (Bbls/d)	Average Price (per Bbl)
Swaps	99	$66.60

*Natural Gas Basis Differential positions*	Volume (MMMBtu/d)	Average Price (per MMBtu)
Southern Star Basis Swaps	5	($ 0.57)
Enable Basis Swaps	5	($ 0.23)


NGL Positions:	2019
Fixed price swap (Mont Belvieu ethane):
Hedged volume (gallons/d in thousands)		126
Average price ($/gallon)		$ 0.34
Fixed price swap (Mont Belvieu propane):
Hedged volume (gallons/d in thousands)		42
Average price ($/gallon)		$ 0.68
Margin spread (Mont Belvieu propane and Conway propane):
Hedged volume (gallons/d in thousands)		63
Average price ($/gallon)		($ 0.07)
Margin spread (Mont Belvieu pentane and Conway pentane):
Hedged volume (gallons/d in thousands)		63
Average price ($/gallon)		($ 0.09)

Earnings Call / Form 10-Q

The Company will host a conference call Thursday, May 9, 2019 at 10:00 a.m. (Central) to discuss the Company’s first quarter 2019 results and expects to file its first quarter Form 10-Q with the Securities and Exchange Commission on or around that date. There will be prepared remarks by executive management followed by a question and answer session.

Investors and analysts are invited to participate in the call by dialing (866) 416-7462, or (409) 217-8223 for international calls using Conference ID: 5959866. Interested parties may also listen over the internet at www.rivieraresourcesinc.com. A replay of the call will be available on the Company’s website.

Supplemental information can be found at the following link on our website: http://ir.rivieraresourcesinc.com/events-and-presentations

Riviera Resources Conference Attendance

Riviera Resources announces that members of senior management will be available for one-on-one meetings with investors in New York City at the RBC Capital Markets Global Energy & Power Conference on June 4, 2019.

ABOUT RIVIERA RESOURCES

Riviera Resources, Inc. is an independent oil and natural gas company with a strategic focus on efficiently operating its mature low-decline assets, developing its growth-oriented assets, and returning capital to its stockholders. Riviera’s properties are located in the Hugoton Basin, East Texas, North Louisiana, Michigan/Illinois, the Uinta Basin and Mid-Continent regions. Riviera also owns Blue Mountain Midstream LLC, a midstream company centered in the core of the Merge play in the Anadarko Basin.

Forward-Looking Statements

Statements made in this press release that are not historical facts are “forward-looking statements.” These statements are based on certain assumptions and expectations made by the Company which reflect management’s experience, estimates and perception of historical trends, current conditions, and anticipated future developments. These statements include, among others, statements regarding our 2019 guidance, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, our strategic objectives with respect to Blue Mountain Midstream, our financial position, business strategy and other plans and objectives for future operations. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or anticipated in the forward-looking statements. These include risks relating to the Company’s financial and operational performance and results, low or declining commodity prices and demand for oil, natural gas and natural gas liquids, ability to hedge future production, ability to replace reserves and efficiently develop current reserves, the capacity and utilization of midstream facilities and the regulatory environment. These and other important factors could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. Please read “Risk Factors” in the Company’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings. The Company undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information or future events.

CONTACT:

Investor Relations

(281) 840-4168

IR@RVRAresources.com

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2019			December 31, 2018
	(in thousands)			(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	102,260		$	18,529
Accounts receivable – trade, net		85,470			114,489
Derivative instruments		3,861			10,758
Restricted cash		26,721			31,248
Other current assets		19,290			26,721
Assets held for sale		—			38,396

Total current assets		237,602			240,141

Noncurrent assets:
Oil and natural gas properties (successful efforts method)		792,861			756,552
Less accumulated depletion and amortization		(103,955	)		(93,507	)

		688,906			663,045
Other property and equipment		629,312			606,244
Less accumulated depreciation		(72,043	)		(62,368	)

		557,269			543,876
Derivative instruments		2,024			4,603
Deferred income taxes		124,598			129,091
Other noncurrent assets		13,695			12,078

		140,317			145,772

Total noncurrent assets		1,386,492			1,352,693

Total assets	$	1,624,094		$	1,592,834

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	154,162		$	159,228
Derivative instruments		5,579			4,719
Current portion of Mayzure notes payable		10,658			—
Other accrued liabilities		18,028			34,474
Liabilities held for sale		—			3,725

Total current liabilities		188,427			202,146

Noncurrent liabilities:
Mayzure notes payable, net		68,671			—
Credit facilities		14,500			24,500
Asset retirement obligations		104,658			103,814
Other noncurrent liabilities		5,689			—

Total noncurrent liabilities		193,518			128,314

Equity:
Preferred Stock		—			—
Common Stock		668			692
Additional paid-in capital		1,223,803			1,256,730
Retained earnings		17,678			4,952

Total equity		1,242,149			1,262,374

Total liabilities and equity	$	1,624,094		$	1,592,834

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended March 31,
	2019			2018
	(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	76,345		$	136,876
Losses on commodity derivatives		(13,241	)		(15,030	)
Marketing revenues		67,347			46,267
Other revenues		6,003			5,894

		136,454			174,007

Expenses:
Lease operating expenses		24,052			47,884
Transportation expenses		19,150			19,094
Marketing expenses		53,389			41,755
General and administrative expenses		19,039			44,779
Exploration costs		1,238			1,202
Depreciation, depletion and amortization		21,772			28,465
Taxes, other than income taxes		6,300			8,452
Gains on sale of assets and other, net		(27,265	)		(106,296	)

		117,675			85,335

Other income and (expenses):
Interest expense, net of amounts capitalized		(971	)		(404	)
Other, net		(589	)		(170	)

		(1,560	)		(574	)

Reorganization items, net		—			(1,951	)

Income from continuing operations before income taxes		17,219			86,147
Income tax expense		4,493			51,539

Income from continuing operations		12,726			34,608
Income from discontinued operations, net of income taxes		—			36,331

Net income	$	12,726		$	70,939

Income per share:
Income from continuing operations per share – Basic	$	0.18		$	0.45

Income from continuing operations per share – Diluted	$	0.18		$	0.45

Income from discontinued operations per share – Basic	$	—		$	0.48

Income from discontinued operations per share – Diluted	$	—		$	0.48

Net income per share – Basic	$	0.18		$	0.93

Net income per share – Diluted	$	0.18		$	0.93

Weighted average shares outstanding – Basic		68,817			76,191

Weighted average shares outstanding – Diluted		69,000			76,191

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
	2019			2018
	(in thousands)
Cash flow from operating activities:
Net income	$	12,726		$	70,939
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		—			(36,331	)
Depreciation, depletion and amortization		21,772			28,465
Deferred income taxes		4,493			52,025
Total losses on derivatives, net		15,421			15,030
Cash settlements on derivatives		(5,085	)		(4,494	)
Share-based compensation expenses		4,236			17,037
Gains on sale of assets and other, net		(28,564	)		(107,223	)
Other		1,583			1,421
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net		26,536			5,415
Decrease in other assets		9,257			12,002
Increase (decrease) in accounts payable and accrued expenses		(15,840	)		13,802
Decrease in other liabilities		(8,857	)		(17,222	)

Net cash provided by operating activities		37,678			50,866

Cash flow from investing activities:
Development of oil and natural gas properties		(30,512	)		(26,024	)
Purchases of other property and equipment		(23,183	)		(46,110	)
Proceeds from sale of properties and equipment and other		60,141			232,394

Net cash provided by investing activities		6,446			160,260

Cash flow from financing activities:
Net transfers to Parent		—			(419,556	)
Repurchases of shares		(34,130	)		—
Proceeds from borrowings		96,225			—
Repayments of debt		(24,300	)		—
Debt issuance costs paid		(2,715	)		(26	)
Distributions to unitholders		—			(8,007	)

Net cash provided by (used in) financing activities		35,080			(427,589	)

Net increase (decrease) in cash, cash equivalents and restricted cash		79,204			(216,463	)
Cash, cash equivalents and restricted cash:
Beginning		49,777			520,922

Ending	$	128,981		$	304,459

Adjusted EBITDAX (Non-GAAP Measure)

The non-GAAP financial measure of adjusted EBITDAX, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, this non-GAAP measure should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for GAAP.

Adjusted EBITDAX is a measure used by Company management to evaluate the Company’s operational performance and for comparisons to the Company’s industry peers. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results.

The following presents a reconciliation of net income to adjusted EBITDAX:


	Three Months Ended March 31,
	2019			2018
	(in thousands)
Net income	$	12,726		$	70,939
Plus (less):
Income from discontinued operations		—			(36,331	)
Interest expense		971			404
Income tax expense		4,493			51,539
Depreciation, depletion and amortization		21,772			28,465
Exploration costs		1,238			1,202

EBITDAX		41,200			116,218
Plus (less):
Noncash losses on commodity derivatives		10,336			10,536
Accrued settlements on commodity derivative contracts related to current production period ⁽¹⁾		(365	)		633
Share-based compensation expenses		6,307			17,037
Gains on sale of assets and other, net⁽²⁾		(28,577	)		(106,332	)
Reorganization items, net ⁽³⁾		—			1,951

Adjusted EBITDAX	$	28,901		$	40,043

⁽¹⁾	Represent amounts related to commodity derivative contracts that settled during the respective period (contract terms had expired) but cash had not been received as of the end of the period.

⁽²⁾	Primarily represent gains or losses on the sale of assets, earnings from equity method investments and gains or losses on inventory valuation.

⁽³⁾

Represent costs and income directly associated with the predecessor’s filing for voluntary reorganization under Chapter 11 of the U.S. Bankruptcy Code since the petition date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined.

Adjusted EBITDAX and Adjusted EBITDA (Non-GAAP Measures)

The non-GAAP financial measure of adjusted EBITDAX and adjusted EBITDA, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, this non-GAAP measure should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP. Adjusted EBITDAX and adjusted EBITDA should not be considered in isolation or as a substitute for GAAP.

Adjusted EBITDAX and adjusted EBITDA is a measure used by Company management to evaluate the Company’s operational performance and for comparisons to the Company’s industry peers. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results.

The following presents a reconciliation of net income (loss) to adjusted EBITDAX and adjusted EBITDA:


	Three Months Ended March 31, 2019
	(in thousands)
	Consolidated			Upstream			Blue Mountain
Net income (loss)	$	12,726		$	15,795		$	(3,069	)
Plus (less):
Interest expense		971			711			260
Income tax expense (benefit)		4,493			4,493			—
Depreciation, depletion and amortization		21,772			19,559			2,213

EBITDA		39,962			40,558			(596	)
Exploration costs		1,238			1,238			—

EBITDAX		41,200			41,796			(596	)
Plus (less):
Noncash losses on commodity derivatives		10,336			6,617			3,719
Accrued settlements on commodity derivative contracts related to current production period ⁽¹⁾		(365	)		(46	)		(319	)
Share-based compensation expenses		6,307			2,230			4,077
Gains on sale of assets and other, net⁽²⁾		(28,577	)		(28,577	)		—

Adjusted EBITDAX / Adjusted EBITDA	$	28,901		$	22,020		$	6,881

⁽¹⁾	Represent amounts related to commodity derivative contracts that settled during the respective period (contract terms had expired) but cash had not been received as of the end of the period.

⁽²⁾	Primarily represent gains or losses on the sale of assets, earnings from equity method investments and gains or losses on inventory valuation.