Riviera Resources Reports Second-Quarter 2019 Results

The Company highlights the following accomplishments:

Increased previously announced $100 million share repurchase authorization to a total of $150 million
Returned over $140 million of capital to shareholders through share repurchases and tender offer since the beginning of the year, and over $290 million in the last twelve months
Closed the sale of certain non-operated properties located in the Hugoton Basin for proceeds of approximately $31 million, and Michigan assets for proceeds of approximately $39 million, both at a premium to PDP PV-10 value
Ended the second quarter with a consolidated cash balance of ~$80 million and $33.5 million drawn on the Blue Mountain Credit Facility

Blue Mountain highlights:

Continued its ongoing engagement with Tudor, Pickering, Holt & Co. to review strategic alternatives to unlock unrealized value
Executed crude oil gathering agreement with Roan Resources, Inc.
Initiated water management services and moved approximately 5.1 million barrels in the second quarter
Acquired 100% interests in Lumen Midstream Partnership, LLC in August 2019, for a total investment of less than $5 million

Riviera Upstream highlights:

Outperformed second quarter upstream guidance, as provided in our May 2019 earnings release, with respect to Adjusted EBITDAX and production, on lower capital spending
Drilled and completed 6 NW STACK operated wells and 2 North Louisiana operated wells in the first half of 2019 with excellent results

David Rottino, Riviera’s President and Chief Executive Officer, commented, “I am very pleased with Riviera’s performance in the second quarter. Operationally, our base assets outperformed original 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 monetized our Arkoma and Michigan assets, a portion of our helium reserves, and our interests in certain non-operated assets in the Hugoton Basin. Additionally, we returned over $140 million of capital to shareholders through our ongoing share repurchase program and recently completed tender offer. Furthermore, the Board authorized an increase to the previously announced $100 million share repurchase program to a total of $150 million. Finally, we continue to grow our exciting Blue Mountain midstream business, and recently announced the execution of a new crude oil gathering agreement with Roan Resources, expanding and diversifying their service offerings, as well as better positioning it towards a value enhancing transaction.”

Key Financial Results ⁽¹⁾

	Three Months Ended		Six Months Ended
	June 30,		June 30,
$ in millions	2019	2018	2019	2018
Average daily production (MMcfe/d)	286	312	275	356
Total oil, natural gas and NGL revenues	$ 67	$ 87	$ 143	$ 224
(Loss) income from continuing operations	$ (7)	$ 9	$ 6	$ 44
(Loss) income from discontinued operations, net of income taxes	$ -	$ (2)	$ -	$ 34
Net (loss) income	$ (7)	$ 7	$ 6	$ 78
Adjusted EBITDAX (a non-GAAP financial measure) ⁽²⁾	$ 35	$ 11	$ 64	$ 51
Net cash provided by operating activities	$ 21	$ 6	$ 59	$ 57
Oil and natural gas capital	$ 16	$ 7	$ 54	$ 17
Total capital	$ 41	$ 42	$ 102	$ 109

(1)	All amounts reflect continuing operations with the exception of net income for the three months and six months ended June 30, 2018, respectively.
(2)	Includes severance costs of approximately $14 million and $18 million for the three months and six months ended June 30, 2018, respectively.

Strategic Update
The Company’s Board of Directors (the “Board”) and management believe the Company is trading at a significant discount to its sum-of-the-parts net asset value. The Company has engaged Tudor, Pickering, Holt & Co. 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.

Opportunistic Asset Monetizations
Thus far in 2019, the Company has closed four transactions that in combination generated proceeds of approximately $216 million. The proceeds from the four deals are at a premium to the PDP PV-10 value. The four transactions include the sale of the Arkoma Basin assets (closed January 2019), the sale of certain non-operated properties located in the Hugoton Basin (closed May 2019), the sale of properties located in Michigan (closed July 2019), and the monetization of a portion of the Company’s helium reserves in the Hugoton Basin utilizing a VPP structure (closed March 2019).

The Company has also signed definitive agreements to sell its interest in properties located in Illinois, and certain non-core properties located in North Louisiana that are expected to close in Q3 2019, that in combination are expected to generate estimated proceeds of approximately $7 million.

Successful Tender Offer
The Company continues to focus on enhancing shareholder value and finding ways to return capital to its shareholders. On June 13, 2019, it announced the intention to commence a tender offer to purchase $40 million of the Company’s common stock. The tender offer was completed on July 16, 2019. The Company repurchased an aggregate of 2,666,666 shares of common stock at a price of $15.00 per share for a total cost of approximately $40 million (excluding expenses of the tender offer). The shares acquired represented approximately 4% of the Company’s outstanding shares as of June 13, 2019.

Continuation of Share Repurchase Plan
On August 16, 2018, the Board authorized the repurchase of up to $100 million of the Company’s outstanding shares of common stock. Through June 2019, the Company repurchased an aggregate of 6,589,110 shares at an average price of $14.56 for a total cost of approximately $96 million. In the second quarter alone the Company bought back 3,147,156 shares at an average price of $13.76 for a total cost of approximately $43 million.

In accordance with the Securities Exchange Commission’s regulations regarding issuer tender offers, the Company’s share repurchase program was suspended concurrent with the June 13, 2019 announcement of the intent to commence a tender offer as discussed above.

The Company expects to continue repurchasing shares, and on July 18, 2019 announced that the Board authorized an increase to the previously announced $100 million share repurchase program to a total of up to $150 million. Subsequent to July 18, 2019, the Company repurchased an aggregate of 2,122,478 shares of common stock for a total cost of approximately $22 million. As of August 7, 2019, approximately $32 million was available for share repurchase under the program.

Second Quarter 2019 Activity – Upstream Assets
Riviera’s production for the second quarter averaged approximately 286 MMcfe/d, which exceeds the high end of our original guidance range. The outperformance in production is mainly due to the outperformance of our NW STACK and North Louisiana drilling programs.

With respect to costs, the Company had strong results in the second quarter. Upstream capital expenditures were approximately $17 million compared to original guidance of $19 million. Adjusted G&A expenses were approximately $7 million. Operating expenses were approximately $44 million, 8% below the mid-point of our original guidance for the quarter, primarily driven by a non-recurring net refund of Texas sales and use tax of approximately $4 million.

Northwest STACK / North Louisiana Operated Drilling Program
Riviera’s operated NW STACK drilling program progressed on schedule with the Company turning to production 3 operated wells in the second quarter, for a total of 6 operated wells turned to production year to date. The average IP30 rate of the 6 operated wells is approximately 670 boepd with 55% oil and 72% liquids. All of these wells are single mile laterals with a target capital cost of $4.9 million to $5.2 million, which is expected to generate a 30% to 40% IRR.

The Company completed a two well pad in North Louisiana late in the first quarter. These wells achieved a choke restricted average IP30 of approximately 20 MMcfe/d. The expected IRR of these wells is over 100% and payback is expected in less than 12 months.

Blue Mountain Business Update
On average for the second quarter of 2019, natural gas throughput was 120 MMcf/d and Natural Gas Liquids (“NGLs”) produced were 10,590 bpd, a 92% increase as compared to the second quarter of 2018 at 62 MMcf/d and a 2% increase compared with the first quarter of 2019 at 117 MMcf/d. During the second quarter, five wells were turned to sales on our system; however, throughput volumes were slightly impacted as our primary customer temporarily shut-in five wells due to hydraulic fracturing of neighboring wells. Throughput volumes are expected to increase during the remainder of 2019 based on the current well attachment schedules provided by our customers. On August 5, 2019, Blue Mountain acquired 100% interests in Lumen Midstream Partnership, LLC, including approximately 55 miles of natural gas gathering pipelines and an 18 MMcf/d processing plant. The Lumen system will be interconnected to the Blue Mountain system for a total investment of less than $5 million. “The acquisition of the Lumen assets will secure over 15 customers, reroute volumes to our Cryo I plant by the fourth quarter and extend our reach into the Merge for our three gathering service options,” commented Greg Harper, President and CEO of Blue Mountain.

On April 1, 2019, Blue Mountain began providing water management services for Roan Resources. During the second quarter, the company hauled 5.1 million barrels of water in total, averaging 56,100 bpd, for Roan Resources and a third-party customer. In addition, during the quarter, Blue Mountain made significant progress in the construction of its water gathering system, with first pipeline connections in service in July. Also, Blue Mountain acquired the land and permits for two of its future owned and operated saltwater disposal wells and expects completion of at least one well by the end of the third quarter of 2019.

During the second quarter of 2019, Blue Mountain was impacted by overall lower commodity prices, including a 20% reduction in the weighted average barrel NGL price from the first quarter of 2019. Despite this major challenge, Blue Mountain’s second quarter Adjusted EBITDA decreased by only $1 million compared with first quarter results, benefited by the new fee-based water margins and steady gas throughput volumes. In the second quarter of 2019, the business continued to be impacted by the NGL pricing differentials at Conway and Mont Belvieu. The elimination of the basis exposure would have added $0.7 million to Blue Mountain’s margin. 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 expenditures for the second quarter were approximately $24 million, with the majority of capital being invested in the construction of water gathering pipelines.

Harper added, “I’m very pleased with Blue Mountain’s performance over the quarter. Our water business is off to a solid start, and we have made significant strides in diversifying our revenue stream going forward with the addition of crude oil gathering. As our water business becomes established moving to our piped system coupled with our recently announced crude oil gathering system, and with Roan’s projected volume ramp during the second half of 2019, I’m excited about our momentum becoming a top tier midstream enterprise as we move towards 2020.”

Balance Sheet and Liquidity
Riviera and Blue Mountain have established separate credit facilities. As of June 30, 2019, there were no borrowings outstanding on Riviera’s revolving credit facility, and borrowing commitments of up to $245 million with available borrowing capacity of approximately $211 million, inclusive of outstanding letters of credit. In July 2019, Riviera’s borrowing base was reduced to $230 million due to the sale of its properties located in Michigan, with available borrowing capacity of approximately $197 million, inclusive of outstanding letters of credit.

As of June 30, 2019, Blue Mountain had approximately $33.5 million drawn on its revolving credit facility, and borrowing commitments of up to $200 million with available borrowing capacity of approximately $155 million, including outstanding letters of credit, subject to covenant restrictions in the Blue Mountain Credit Facility.

Second Quarter Actuals
Below is a summary of the Company’s consolidated second quarter results.

	Q2 2019 Actuals	Q2 2019 Actuals	Q2 2019 Actuals
	Upstream	Blue Mountain	Consolidated

Net Production (MMcfe/d)	286		286
Natural gas (MMcf/d)	236		236
Oil (Bbls/d)	1,933		1,933
NGL (Bbls/d)	6,363		6,363

Other revenues, net (in thousands)⁽¹⁾	$ 8,064 ⁽²⁾	$ 11,668 ⁽³⁾	$ 19,732 ⁽⁴⁾
Helium revenues	$ 4,810 ⁽⁵⁾		$ 4,810 ⁽⁵⁾
Jayhawk / Other	$ 3,254		$ 3,254
Blue Mountain		$ 11,668 ⁽³⁾	$ 11,668⁽³⁾

Costs (in thousands)	$ 43,789	$ 708	$ 44,497
Lease operating expenses	$ 23,845		$ 23,845
Transportation expenses	$ 18,053		$ 18,053
Taxes, other than income taxes	$ 1,891 ⁽⁶⁾	$ 708	$ 2,599 ⁽⁶⁾

Adjusted general and administrative expenses (Non-GAAP) ⁽⁷⁾	$ 6,990 ⁽⁸⁾	$ 2,875 ⁽⁹⁾	$ 9,865 ⁽¹⁰⁾

Targets (in thousands)
Adjusted EBITDAX (Non-GAAP)	$ 28,761	$ 5,887	$ 34,648
Cash interest expense (Non-GAAP) ⁽¹¹⁾	$ 999	$ 229	$ 1,228
Oil and natural gas capital	$ 16,054		$ 16,054
Total capital	$ 17,291	$ 23,539	$ 40,830

(1)	Includes other revenues and margin on marketing activities
(2)	Includes other revenues of approximately $5.2 million, plus marketing revenues of approximately $10.7 million, less marketing expenses of approximately $7.8 million for the three months ended June 30, 2019
(3)	Includes marketing revenues of approximately $42.6 million, less adjusted marketing expenses of approximately $30.9 million. Adjusted marketing expenses is a non-GAAP measure that excludes share-based compensation expenses of less than $0.1 million
(4)	Includes other revenues of approximately $5.2 million, plus marketing revenues of approximately $53.3 million, less adjusted marketing expenses of approximately $38.8 million. Adjusted marketing expenses is a non-GAAP measure that excludes share-based compensation expenses of less than $0.1 million and losses on derivatives of approximately $2.9 million
(5)	Includes helium revenues from the VPP Interests of approximately $3.7 million
(6)	Includes a reduction to taxes, other than income taxes costs for non-recurring refund of Texas sales and use tax, net of professional service claim fees, of approximately $4.4 million
(7)	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
(8)	For the three months ended June 30, 2019 represents general and administrative expenses of approximately $8.8 million, excluding share-based compensation expenses of approximately $1.8 million
(9)	For the three months ended June 30, 2019 represents general and administrative expenses of approximately $4.7 million, excluding share-based compensation expenses of approximately $1.8 million
(10)	For the three months ended June 30, 2019 represents general and administrative expenses of approximately $13.5 million, excluding share-based compensation expenses of approximately $3.6 million
(11)	Excludes non cash amortization

Upstream Segment - Second Quarter Actuals versus Guidance
The comparison to guidance below is for the upstream assets only. The Company did not provide second quarter 2019 guidance for Blue Mountain.

	Q2 2019 Actuals	Original Guidance ⁽¹⁾ Q2 2019E	Updated Guidance ⁽¹⁾ Q2 2019E

Net Production (MMcfe/d)	286	255 – 285	280 – 290
Natural gas (MMcf/d)	236	210 – 235	230 – 240
Oil (Bbls/d)	1,933	1,600 – 1,850	1,875 – 2,000
NGL (Bbls/d)	6,363	5,900 – 6,500	6,300 – 6,400

Other revenues, net (in thousands)⁽²⁾	$ 8,064 ⁽³⁾	$ 5,500 - $ 7,500	$ 7,000 – $ 8,500
Helium revenues	$ 4,810 ⁽⁴⁾	$ 4,500 – $ 5,500 ⁽⁴⁾	$ 4,500 – $ 5,000 ⁽⁴⁾
Jayhawk / Other	$ 3,254	$ 1,000 – $ 2,000	$ 2,500 – $ 3,500

Costs (in thousands)	$ 43,789	$ 45,000 – $ 50,000	$ 42,000 – $ 46,000
Lease operating expenses	$ 23,845	$ 23,000 – $ 25,000	$ 23,000 – $ 25,000
Transportation expenses	$ 18,053	$ 17,000 – $ 18,000	$ 17,500 – $ 18,500
Taxes, other than income taxes	$ 1,891 ⁽⁵⁾	$ 5,000 – $ 7,000	$ 1,500 – $ 2,500 ⁽⁴⁾

Adjusted general and administrative expenses (Non-GAAP) ⁽⁶⁾	$ 6,990 ⁽⁷⁾	$ 7,500 – $ 9,000	$ 6,500 – $ 7,500

Targets (Mid-Point) (in thousands)
Adjusted EBITDAX (Non-GAAP)	$ 28,761	$ 23,000	$ 25,000 – $ 30,000
VPP Notes interest expense ⁽⁸⁾	$ 1,045	$ 1,000	$ 1,050
VPP Notes principal	$ 2,649	$ 3,000	$ 2,650
Capital expenditures	$ 17,291	$ 19,000	$ 17,500

(1)	Original guidance estimates provided in May 9, 2019 first quarter earnings release; updated guidance provided in July 9, 2019 press release
(2)	Includes other revenues and margin on marketing activities
(3)	Includes other revenues of approximately $5.2 million, plus marketing revenues of approximately $10.7 million, less marketing expenses of approximately $7.8 million for the three months ended June 30, 2019
(4)	Includes helium revenues from the VPP Interests of approximately $3.7 million
(5)	Includes a reduction to taxes, other than income taxes costs for non-recurring refund of Texas sales and use tax, net of professional service claim fees, of approximately $4.4 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 June 30, 2019 represents general and administrative expenses of approximately $8.8 million, excluding share-based compensation expenses of approximately $1.8 million
(8)	Excludes non cash amortization

Upstream Segment - Third Quarter and Full Year 2019 Guidance
The guidance below is for the upstream assets only. Guidance estimates have been adjusted for the sale of properties located in Michigan that closed July 3, 2019, and the sales of Illinois assets and non-core North Louisiana properties that are expected to close in the third quarter. 2019 guidance estimates include the Adjusted EBITDAX from the Helium VPP transaction that closed in March, 2019.

	Q3 2019E	FY 2019E

Net Production (MMcfe/d)	233 – 255	240 – 270
Natural gas (MMcf/d)	185 – 205	195 – 220
Oil (Bbls/d)	1,900 – 2,100	1,500 – 1,800
NGL (Bbls/d)	6,000 – 6,300	6,000 – 6,500

Other revenues, net (in thousands)⁽¹⁾	$ 7,000 - $ 9,000	$ 36,000 – $ 40,000
Helium revenues	$ 4,500 – $ 5,500 ⁽²⁾	$ 20,000 – $ 22,000 ⁽³⁾
Jayhawk / Other	$ 2,500 – $ 3,500	$ 16,000 – $ 18,000

Costs (in thousands)	$ 36,500 – $ 41,500	$ 165,000 – $ 175,000
Lease operating expenses	$ 17,000 – $ 19,000	$ 81,000 – $ 85,000
Transportation expenses	$ 16,000 – $ 17,000	$ 68,000 – $ 72,000
Taxes, other than income taxes	$ 3,500 – $ 5,500	$ 16,000 – $ 18,000

Adjusted general and administrative expenses (Non-GAAP) ^{(4), (6)}	$ 8,500 – $ 9,500	$ 32,000 – $ 35,000
General and administrative- severance expenses	$ 1,500 - $ 2,000	$ 1,500 - $ 2,000

Costs per Mcfe (Mid-Point)	$ 1.75	$ 1.82
Lease operating expenses	$ 0.80	$ 0.89
Transportation expenses	$ 0.74	$ 0.75
Taxes, other than income taxes	$ 0.21	$ 0.18

Targets (Mid-Point in thousands)
Adjusted EBITDAX (Non-GAAP) ^{(5), (6)}	$ 19,000	$ 91,000
Capital expenditures	$ 9,000	$ 68,000
VPP Notes interest expense payments	$ 1,000	$ 3,000
VPP Notes principal payments	$ 2,700	$ 8,000

Weighted Average NYMEX Differentials
Natural gas (MMBtu)	($ 0.55) – ($ 0.40)	($ 0.40) – ($ 0.30)
Oil (Bbl)	($ 2.40) – ($ 1.40)	($ 1.70) – ($ 1.10)
NGL price as a % of crude oil price	24% – 30%	28% – 34%

Unhedged Commodity Price Assumptions	Jul 19	Aug 19	Sep 19	2019E
Natural gas (MMBtu)	$2.29	$2.22	$2.20	$2.59
Oil (Bbl)	$57.75	$55.88	$55.88	$56.82
NGL (Bbl)	$15.34	$14.86	$14.83	$17.79

(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 and severance expenses
(5)	Includes severance expenses of approximately $1.8 million
(6)	The Company does not provide a reconciliation of such non-GAAP financial measures to the most directly comparable GAAP financial measures on a forward-looking basis as it is unable to forecast certain items that we have defined as "Selected Items Impacting Comparability", which items are set forth later in this press release under the heading “Non-GAAP Financial Measures and Selected Items Impacting Comparability,” without unreasonable effort, due to the uncertainty and inherent difficulty of predicting the occurrence and financial impact of and the periods in which such items may be recognized. Thus, a reconciliation of such non-GAAP financial measures to the most directly comparable GAAP financial measures could result in disclosure that could be imprecise or potentially misleading. These items could be material to and have a significant impact on the Company’s results computed in accordance with GAAP.

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)
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	98	$ 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, August 8, 2019 at 10:00 a.m. (Central) to discuss the Company’s second quarter 2019 results and expects to file its second 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: 5655538. 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 Orleans at the Johnson Rice 2019 Energy Conference on September 25, 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, 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.

Non-GAAP Financial Measures and Selected Items Impacting Comparability
To supplement our financial information presented in accordance with GAAP, management uses additional measures known as "non-GAAP financial measures" in its evaluation of past performance and prospects for the future. The primary additional measures used by management are earnings before interest, taxes, depreciation and amortization, exploration costs, noncash gains and losses on commodity derivatives, accrued settlements on commodity derivative contracts related to current production period, share-based compensation expenses, gains and losses on asset sales, reorganization items, and asset impairments (“Adjusted EBITDAX”) and earnings before interest, taxes, depreciation and amortization, noncash gains and losses on commodity derivatives, accrued settlements on commodity derivative contracts related to current production period, share-based compensation expenses, gains and losses on asset sales, and asset impairments (“Adjusted EBITDA”). Management believes these non-GAAP financial measures provide useful information to investors because these non-GAAP measures, when viewed with the Company’s GAAP results and accompanying reconciliations, provide a more complete understanding of the Company’s performance than GAAP results alone.

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)
	June 30, 2019		December 31, 2018
	(in thousands)		(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	80,229	$	18,529
Accounts receivable – trade, net		82,218		114,489
Derivative instruments		18,447		10,758
Restricted cash		26,457		31,248
Other current assets		14,638		26,721
Assets held for sale		49,090		38,396
Total current assets		271,079		240,141
Noncurrent assets:
Oil and natural gas properties (successful efforts method)		692,815		756,552
Less accumulated depletion and amortization		(101,033)		(93,507)
		591,782		663,045

Other property and equipment		646,425		606,244
Less accumulated depreciation		(79,275)		(62,368)
		567,150		543,876

Derivative instruments		2,048		4,603
Deferred income taxes		126,646		129,091
Other noncurrent assets		7,389		12,078
		136,083		145,772
Total noncurrent assets		1,295,015		1,352,693
Total assets	$	1,566,094	$	1,592,834
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	122,188	$	159,228
Derivative instruments		5,471		4,719
Current portion of Mayzure notes payable		10,693		—
Other accrued liabilities		24,656		34,474
Liabilities held for sale		10,303		3,725
Total current liabilities		173,311		202,146
Noncurrent liabilities:
Derivative instruments		166		—
Mayzure notes payable, net		65,841		—
Credit facilities		33,500		24,500
Asset retirement obligations		91,480		103,814
Other noncurrent liabilities		9,630		—
Total noncurrent liabilities		200,617		128,314
Equity:
Preferred Stock		—		—
Common Stock		636		692
Additional paid-in capital		1,180,528		1,256,730
Retained earnings		11,002		4,952
Total equity		1,192,166		1,262,374
Total liabilities and equity	$	1,566,094	$	1,592,834

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018

	(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	66,757	$	87,004	$	143,102	$	223,880
Gains (losses) on commodity derivatives		20,249		(7,525)		7,008		(22,555)
Marketing revenues		53,394		42,967		120,741		89,234
Other revenues		5,150		6,387		11,153		12,281
		145,550		128,833		282,004		302,840
Expenses:
Lease operating expenses		23,845		24,088		47,897		71,972
Transportation expenses		18,053		21,213		37,203		40,307
Marketing expenses		41,811		40,327		95,200		82,082
General and administrative expenses		13,489		92,395		32,480		137,174
Exploration costs		969		53		2,207		1,255
Depreciation, depletion and amortization		23,181		21,980		44,953		50,445
Impairment of assets held for sale		18,390		—		18,390		—
Taxes, other than income taxes		2,599		7,115		8,899		15,567
Losses (gains) on sale of assets and other, net		9,885		(101,934)		(17,380)		(208,230)
		152,174		105,237		269,849		190,572
Other income and (expenses):
Interest expense, net of amounts capitalized		(2,103)		(584)		(3,074)		(988)
Other, net		476		538		(113)		368
		(1,627)		(46)		(3,187)		(620)
Reorganization items, net		(424)		(1,259)		(472)		(3,210)
(Loss) income from continuing operations before income taxes		(8,723)		22,291		8,496		108,438
Income tax (benefit) expense		(2,047)		13,336		2,446		64,875
(Loss) income from continuing operations		(6,676)		8,955		6,050		43,563
Income (loss) from discontinued operations, net of income taxes		—		(1,758)		—		34,573
Net (loss) income	$	(6,676)	$	7,197	$	6,050	$	78,136
Income (loss) per share:
(Loss) income from continuing operations per share ‒ Basic	$	(0.10)	$	0.11	$	0.09	$	0.58
(Loss) income from continuing operations per share ‒ Diluted	$	(0.10)	$	0.11	$	0.09	$	0.58

Income (loss) from discontinued operations per share ‒ Basic	$	—	$	(0.02)	$	—	$	0.45
Income (loss) from discontinued operations per share ‒ Diluted	$	—	$	(0.02)	$	—	$	0.45

Net (loss) income per share ‒ Basic	$	(0.10)	$	0.09	$	0.09	$	1.03
Net (loss) income per share ‒ Diluted	$	(0.10)	$	0.09	$	0.09	$	1.03

Weighted average shares outstanding ‒ Basic		65,005		76,191		66,900		76,191
Weighted average shares outstanding ‒ Diluted		65,089		76,191		67,079		76,191

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)



	Six Months Ended June 30,
	2019		2018

	(in thousands)
Cash flow from operating activities:
Net income	$	6,050	$	78,136
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		—		(34,573)
Depreciation, depletion and amortization		44,953		50,445
Impairment of assets held for sale		18,390		—
Deferred income taxes		2,446		65,010
Total (gains) losses on derivatives, net		(2,047)		22,555
Cash settlements on derivatives		(2,169)		(25,037)
Share-based compensation expenses		7,885		66,374
Gains on sale of assets and other, net		(19,631)		(209,635)
Other		4,220		2,008
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net		28,361		76,465
Decrease in other assets		10,901		33,654
Decrease in accounts payable and accrued expenses		(32,119)		(52,538)
Decrease in other liabilities		(8,439)		(15,815)
Net cash provided by operating activities		58,801		57,049
Cash flow from investing activities:
Development of oil and natural gas properties		(56,078)		(45,938)
Purchases of other property and equipment		(48,597)		(87,377)
Proceeds from sale of properties and equipment and other		95,291		369,489
Net cash (used in) provided by investing activities		(9,384)		236,174
Cash flow from financing activities:
Net transfers to Parent		—		(456,925)
Repurchases of shares		(77,744)		—
Proceeds from borrowings		115,225		—
Repayments of debt		(26,949)		—
Debt issuance costs paid		(3,040)		—
Distributions to unitholders		—		(12,174)
Other		—		(294)
Net cash provided by (used in) financing activities		7,492		(469,393)
Net increase (decrease) in cash, cash equivalents and restricted cash		56,909		(176,170)
Cash, cash equivalents and restricted cash:
Beginning		49,777		520,922
Ending	$	106,686	$	344,752

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 (loss) to Adjusted EBITDAX:

	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018

	(in thousands)
Net (loss) income	$	(6,676)	$	7,197	$	6,050	$	78,136
Plus (less):
Loss (income) from discontinued operations		—		1,758		—		(34,573)
Interest expense, net of amounts capitalized		2,103		584		3,074		988
Income tax (benefit) expense		(2,047)		13,336		2,446		64,875
Depreciation, depletion and amortization		23,181		21,980		44,953		50,445
Exploration costs		969		53		2,207		1,255
EBITDAX		17,530		44,908		58,730		161,126
Plus (less):
Noncash (gains) losses on commodity derivatives		(14,552)		6,955		(4,216)		17,491
Accrued settlements on commodity derivative contracts related to current production period ⁽¹⁾		(663)		935		(1,028)		1,568
Share-based compensation expenses		3,680		58,188		9,987		75,225
Losses (gains) on sale of assets and other, net ⁽²⁾		9,839		(100,928)		(18,786)		(207,260)
Reorganization items, net ⁽³⁾		424		1,259		472		3,210
Impairment of assets held for sale		18,390		—		18,390		—
Adjusted EBITDAX	$	34,648	$	11,317	$	63,549	$	51,360

⁽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 measures of Adjusted EBITDAX and adjusted EBITDA, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP measures 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 are measures 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 June 30, 2019
	(in thousands)
	Consolidated		Upstream		Blue Mountain

Net (loss) income	$	(6,676)	$	(7,308)	$	632
Plus (less):
Interest expense		2,103		1,748		355
Income tax benefit		(2,047)		(2,047)		—
Depreciation, depletion and amortization		23,181		20,970		2,211
EBITDA		16,561		13,363		3,198
Exploration costs		969		969		—
EBITDAX		17,530		14,332		3,198
Plus (less):
Noncash (gains) losses on commodity derivatives		(14,552)		(15,282)		730
Accrued settlements on commodity derivative contracts related to current production period ⁽¹⁾		(663)		97		(760)
Share-based compensation expenses		3,680		1,770		1,910
Losses on sale of assets and other, net ⁽²⁾		9,839		9,030		809
Reorganization items, net ⁽³⁾		424		424		—
Impairment of assets held for sale		18,390		18,390		—
Adjusted EBITDAX / Adjusted EBITDA	$	34,648	$	28,761	$	5,887

	Six Months Ended June 30, 2019
	(in thousands)
	Consolidated		Upstream		Blue Mountain

Net income (loss)	$	6,050	$	8,487	$	(2,437)
Plus (less):
Interest expense	3,074			2,459		615
Income tax expense	2,446			2,446		—
Depreciation, depletion and amortization		44,953		40,529		4,424
EBITDA	56,523			53,921		2,602
Exploration costs		2,207		2,207		—
EBITDAX	58,730			56,128		2,602
Plus (less):
Noncash (gains) losses on commodity derivatives	(4,216)			(8,665)		4,449
Accrued settlements on commodity derivative contracts related to current production period ⁽¹⁾	(1,028)			51		(1,079)
Share-based compensation expenses	9,987			4,000		5,987
(Gains) losses on sale of assets and other, net ⁽²⁾	(18,786)			(19,595)		809
Reorganization items, net ⁽³⁾	472			472		—
Impairment of assets held for sale		18,390		18,390		—
Adjusted EBITDAX / Adjusted EBITDA	$	63,549	$	50,781	$	12,768




⁽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.

Press Release

Riviera Resources Reports Second-Quarter 2019 Results