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Petro ScoutApril 26, 2017

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NORTH LOUISIANA SALE PKG 2-Packages.HAYNESVILLE SHALE PPCOTTON VALLEY & HOSSTONRefrac & Recompletion Upside. ~750Operated & NonOperated WI Available BOEDCurrent Net Production: ~750 BOEDFLEXIBLE SELLER (OP OR NONOP)PP 9049PKG

WEST TEXAS NONOP PROPERTY41-Producing Wells. 2-ShutIn Wells. GAINES & ANDREWS COUNTIESWichita Albany, San Andres & Lower PPClearfork Formations1,840 Gross Acres. 641 Net Acres. ~240NonOperated WI Available BOEDNet Production: 242 BOEDPLS IS PREPARING PACKAGEPP 4365

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PDC Energy raises EURs in Wattenberg field

PDC Energy unveiled increased type curves for extended-reach and mid-reach wells in Wattenberg as a result of new completion design. The company raised its type curve for XRL wells, which it just began drilling last year, by 30% to 1.1 MMboe and its MRL type curve 15% to 800,000 boe. The SRL type curve remains at 490,000 boe because none of the wells that came online last year were completed with the latest design.

PDC’s well-design evolution began just two years ago, when it began its transition to plug-and-perf from sliding sleeve and monobore drilling. It also began drilling MRLs that year. In 2016, PDC began drilling its first XRL wells and tested stage spacing down to 140 ft with a variety of undisclosed proppant loads. The company will move to 100-140-ft spacing this year while still experimenting with proppant volumes.

Haynesville, Bossier contain over 300 Tcf recoverableUSGS increases 2010 estimate of 70 Tcf more than 4x

The USGS updated its assessment of the Haynesville and Bossier formations along the US Gulf Coast to 304.4 Tcf, 4.0 Bbo and 1.9 Bbbl of NGLs in mean undiscovered, technically recoverable resource. This is more than four times the agency’s 2010

assessment of the formations. It also surpasses the USGS’ first assessments of the Appalachian

Basin’s Marcellus (84 Tcf, 3.4 Bbbl NGLs) and Utica (38.2 Tcf, 940 MMbo, 208 MMbbl NGLs) formations earlier this decade, making this the agency’s largest-ever continuous natural gas assessment. “It’s amazing what a little more knowledge can yield,” said USGS scientist Stan Paxton, lead author of the assessment. “Since the 2010 assessment, we’ve gotten updated geologic maps, expanded production history and have a greater understanding of how these reservoirs evolved.”

Broken down, the USGS now estimates that the Haynesville contains 195.8 Tcf, 1.1 Bbo and 900,000 MMbbl of NGLs. The Bossier holds 108.6 Tcf, 2.9 Bbo and 1.0 Bbbl of NGLs. The initial assessment back in 2010 pegged the Haynesville at 61.4 Tcf and the Bossier at 9.0 Tcf.

Hilcorp to put conventional expertise to work in San JuanHilcorp continues to bet on conventional resources in the unconventional age.

The private player became a San Juan Basin operator earlier this month by picking up ConocoPhillips’ 1.3-million-acre position in a deal worth $3.0 billion. Hilcorp was mum on specific plans for the assets, but the deal marks a footprint expansion and makes the company the largest private gas producer in the US, according to

data compiled by the Oil and Gas Financial Journal. Hilcorp now operates more than 1.5 Bcfe/d.

Since its founding in 1989, the private operator has built a premier asset base focused on developing and optimizing fields in Alaska, the Northeast and the Gulf Coast. The gas producer racks up its successes in a less popular way—squeezing additional oil and gas out of aging conventional fields. Hilcorp was consistently the most active operator across the Gulf Coast during the downturn. Now it has a new basin to go to work in.

New round of Powder River drilling highlights potentialAccelerated programs to delineate stacked intervals in Wyoming’s Powder River

Basin are beginning to yield results for operators such as Chesapeake, Devon and EOG. Each of these companies initiated plans late last year to test new zones or apply enhanced drilling and completion techniques to established zones. Initial rates from these wells have

been encouraging. With up to 10

target zones, high oil content, a 4,000-ft gross hydrocarbon column and overpressured reservoirs, the recently relaunched Samson Resources says the Powder River Basin’s potential is comparable to a nascent Delaware Basin. And Chesapeake EVP Frank Patterson likened his company’s position to Colorado’s Wattenberg field during its Analyst Day last October, when he announced plans to accelerate Powder River drilling. Operators see high potential to increase well rates in the Powder River, where they have generally averaged laterals of ~5,000 ft and proppant loading of ~1,000 lb per foot versus ~7,500 ft and ~2,500-5,000 lb per foot in the Permian and Eagle Ford.

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Potential compared to Wattenberg or early-stage Delaware Basin.

Operator becomes largest private gas producer at 1.5 Bcfe/d.

New assessment 4x USGS’ original resource estimate.

Nascent XRL program gets 30% type curve increase to 1.1 MMboe.Continues On Pg 18

Continues On Pg 19

Continues On Pg 4

Continues On Pg 20

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PetroScout 2 April 26, 2017

Eastern ■ Calgary-based Baytex Energy

increased its Eagle Ford IP-30 rates by 20% to 1,300 boe/d from 2015 to 2016. The company began production on 123 wells (36.3 net) in 2016 and ramped up its rig count late in the year to five. It plans to operate at that level throughout 2017, and completion activity will remain relatively flat. Baytex will allocate 70% of its $300-350 million capex to the play.

■ Denver-based Carbon Natural Gas and two institutional investors have formed Carbon Appalachia Co. to develop the Chattanooga shale in Tennessee with an initial equity commitment of $100 million. The company expects to start field production enhancement projects in 2H17. Current volumes are 3.6 MMcfe/d (92% gas), but Carbon Appalachia estimates the properties contain PD reserves of 23.8 Bcfe (86% PDP).

Drillbits

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Vine accelerates in Haynesville as it goes publicVine Resources is running eight to nine rigs this year in the Haynesville with plans

to develop 44 operated wells on capex of $320 million. This activity level is up from 2016, when it spent $155 million on D&C and averaged five rigs. Vine will also refrac six older wells.

The Blackstone Group-backed private player i filed for an IPO in mid-April in a signal of the Haynesville resurgence. Vine is the first of a trio of active private operators—the other two being Indigo Minerals and Covey Park—to go public.

So far in 2017, Vine has averaged 12.0 MMcf/d IPs on wells with 5,000-ft laterals. About 40% of this year’s program wells will sport 5,000-ft laterals. The company considers anything over 5,000 ft to be a long lateral. Average well costs are $7.9 million for standard laterals and $10.7 million for long laterals.

Vine entered the Haynesville in 2014 through the acquisition of 107,000 net acres from Shell and has since brought 47 wells online across Red River, DeSoto and Sabine parishes. Vine said in its S-1 filing that it achieved 48% CAGR from 3Q15 to 4Q16. For full-year 2016, Vine averaged 218 MMcf/d.

Vine said in its S-1 filing that more than 60% of its position is prospective for dual-zone development with 1,724 locations. Of those, 1,239 are standard laterals and 485 are long laterals. The company estimates it has more than 22 years of drilling inventory assuming an eight-rig pace and six wells per 640-acre section.

ARK-LA-TEX SCOUT

EXCO Lengthens Laterals and Reduces Costs

East Texas Lateral Length And Days To Drill 10-15E; �; Days

East Texas D&C Cost Per Lateral Foot 10-15E; $/�

East Texas Drilling Cost Per Foot 10-15E; $/�

East Texas Proppant Per Lateral Foot 10-15E; lbs/�

800 850 950 1,400

2,700

10 11 12 14 Current

4,717 4,675 5,090 6,520

7,500

59 54 52

47 46

0

10

20

30

40

50

60

70

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

10 11 12 14 Current

Days to drill

3,011 2,870 2,193 1,910

1,383

10 11 12 14 Current

348 360 316

270 201

10 11 12 14 Current

Source: EXCO Resources October 28, 2015 via PLS docFinder (www.plsx.com/finder)

Regional Activity (State Data)(10/19/15 to 11/09/15)

Compls PermitsArkansas 16 8

North Louisiana – 45

East Texas (RRC 5) 1 12

East Texas (RRC 6) 15 24

Most Active Operators by Permits➊ Cavalcade Operating 23

➋ Chesapeake 9

➌ EXCO Operating 6

Permits by Formation (by Last Scout)

Formation 11/12 10/22 10/01Haynesville 17 24 11Cotton Valley 10 10 8Fayetteville 5 7 6Travis Peak 5 3 4Barnett 4 2 1Shallow 4 – –Pettit 2 2 –Rodessa 2 1 2Blossom 1 1 –Other Formations 39 29 125TOTAL 89 79 157Source: TXRRC, SONRIS & AOGC

Active Rigs Running (Baker Hughes) 55

Comstock’s Haynesville completions exceeding estimatesEnhanced completion designs have

driven IP rates for Comstock Resources’ Haynesville wells above its 15.6 Bcf type curve, causing a 119% jump in Haynesville production over two quarters. Comstock’s

Q3 production from the Haynesville averaged 105 MMcf/d, up from 77 MMcf/d in Q2 and 46 MMcf/d in Q1.

Comstock’s first eight Haynesville wells had average IP rates of 24 MMcf/d. The company says it is using longer

laterals and increased stimulation in its completion designs. The Haynesville wells it drilled this year have average laterals of

7,280 ft. The company also saw a 9 MMcf/d gain

in production from older offset wells after using a new refrac system that works from the wellbore out into the reservoir.

In addition, Comstock reduced its Haynesville D&C costs to $9.3 million per well, down from the $11.3 million cost for its first Haynesville well. It has also reduced its drilling time from 30 days in Q1 to 23 days at present.

EXCO zeroes in on Shelby as it continues to outperformAfter ceasing its North Louisiana

drilling program earlier this year, EXCO Resources is narrowing its focus on the Shelby area of East Texas. The company says its Haynesville and Bossier gas wells at Shelby are generating superior returns thanks to advanced completion methods.

During Q3, EXCO ran three rigs and drilled five operated horizontals (four Haynesville and one Bossier) at Shelby. East Texas production was 52 MMcfe/d—

up 30% sequentially and 108% YOY. Results YTD from EXCO’s Shelby have outperformed the company’s type curves, which predict EURs per 1,000 lateral ft of

1.5 Bcf for the Haynesville and 1.3 Bcf for the Bossier. EXCO’s optimized completions use more than 2,700 lb/ft of proppant. It has also been drilling average laterals of more than 7,000 ft this year.

Frac design using 2,700 lb/ft of proppant yields high East Texas results.

Haynesville production up 119% YTD to an average of 105 MMcf/d.

Continues On Pg 3

Continues On Pg 12

Regional Oil & Gas Intelligence November 12, 2015

Serving the local market with drilling activity, permits & deals for sale Volume 03, No. 14

LEON CO., TX PROSPECT226-Acres. 2-Potential Wells.WOODBINE SAND/OSR HALLIDAY DVWoodbine Sand Objective. <7,000 Ft.Subsurface Geology Data AvailableUp to 25% NonOp WI; 75% NRI WOOD-Expected IP: 700 BOPD + 5.0 MMCFD BINEEst Well Reserves: 500+ MBO/WellDV 2619

NAVARRO CO., TX PROSPECT6,500-Acres. 6-Potential Wells.EAST TEXAS BASIN DVObj 1: Smackover. 8,700 Ft.Obj 2: Norphlett. 9,000 Ft.100% OPERATED WI; 75% NRI EASTExpected IP(Smackover): 12 MMCFD TXEst Net Rsrvs: 400 MBO + 20 BCF/WellDV 2583

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88 Completions; 90 Permits; 55 Rigs Running.

Ark-La-Tex Scout April 13

Has grown volumes 48%; brought 47 wells online since Shell buy.

Ark-La-Tex

Regional Oil & Gas Intelligence November 10, 2015

Serving the local market with drilling activity, permits & deals for sale Volume 02, No. 15

Deals For Sale

MERCER CO., OH PROSPECT10,000-Contiguous Acres.SHALLOW TRENTON DVHISTORICAL OIL PLAYShallow Trenton Blanket. 1,100 Ft.100% OPERATED WI AVAILABLETERMS NEGOTIABLE TRENTONCONTACT LEASE OWNER FOR INFODV 3012L

WESTERN PA MARCELLUS LEASE417-Acres.EXCO NOT RENEWING LARMSTRONG COUNTYAvailable Due to Vertical Pugh Clause.Includes Burkett & Utica Shale. MARCELLUS/GROUND FLOOR OPPORTUNITY UTICANRI And Terms Are Negotiable.L 6947

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Gulfport cutting back on eastern Ohio productionIn its Q3 results update, Gulfport

Energy announced it is cutting 100 MMcf/d, or ~15%, of its Utica shale production in Ohio until early 2016. The company hopes gas prices will rise and says it will save $500,000/well by not fracking this winter.

Gulfport says it has scrapped its plans to add a fifth rig to its Utica program and will instead continue to run four. A fracking crew will also be idled.

The company drilled 15 Utica wells in Q3 and began production on 16 more, and it dropped drilling costs 5-8%. Last month, Gulfport entered into a Utica shale JV with Rice Energy for a dry gas gathering

system. The project, in which Gulfport has a 25% stake to Rice’s 75%,

includes the system with a capacity of more than 1.76 Bcf/d and more than 165 miles of pipelines with multiple connections to interstate lines, 50,000 horsepower of compression for gathering and delivery, and a fresh water distribution system.

EQT encouraged by ongoing deep Utica resultsJust a few months after bringing its

record-breaking dry gas Utica well online, EQT Corp. is banking on the play as a potential paradigm shifter. The company has suspended drilling outside of its core area in southwestern Pennsylvania and West Virginia to switch its focus to wells with the highest returns.

Back in July, EQT tested the Scotts Run #591340 in Greene County, Pennsylvania, at a 24-hour rate of 72.9 MMcf/d. Reservoir modeling suggests an EUR of 4.3-5.9 Bcf

per 1,000 ft of lateral for the Scotts Run well. The company says that at present, the well is flowing into the sales pipeline at a choke-restricted rate of 30 MMcf/d.

“A year ago, it would have been hard to imagine a more prolific play than the Marcellus. However, if the deep Utica works, it is likely to be larger than the Marcellus over time,” CEO David Porges said on EQT’s Q3 earnings call.

Will no longer be adding a fifth rig to Utica; will continue running four.

Regional Activity (State Data)(10/05/15 to 11/04/15)

Compls PermitsIllinois – 23Indiana – 9Kentucky – 31New York – 2Ohio – 78Pennsylvania – 166Tennessee – 4West Virginia 51 53

Most Active Operators by Permits➊ EQT Production 27➋ SWN Production 24➌ Titusville O&G 20

Permits by Formation (by Last Scout)

Formation 11/10 10/20 09/28Marcellus 25 27 32Clinton 19 20 17Utica/Point Pleasant 18 48 31Knox GP 17 16 4Point Pleasant 17 24 11St Louis 10 4 2Trenton 9 4 2Warsaw 6 3 4Aux Vases 4 3 2Other Formations 241 260 237TOTAL 366 409 342Source: Illinois DNR, Indiana DNR, KYDOG, NYSDEC, ODNR, PADEP, TDEC & WVDEPActive Rigs Running (Baker Hughes) 68

Continues On Pg 14

Well tested at 72.9 MMcf/d flowing to sales at choke-restricted 30 MMcf/d.

Dry Gas Utica - Top Wells

Well Name County OperatorPeak Rate (MMcfe/d)

Peak Rate (boe/d)

Lateral Length Stages

Scotts Run Greene, PA EQT 72.9 12,150 3,221 N/A

Claysville Sportsman 11H Washington, PA RRC 59.0 9,833 5,420 N/A

Stewart Winland 1300U Tyler, WV MHR 46.5 7,750 5,289 22

Bigfoot #9H Belmont, OH RICE 41.7 6,948 6,957 40

Yontz 1H Monroe, OH AR 38.9 6,483 5,115 N/A

Blake U-7H Marshall, WV GST 36.8 6,133 6,617 N/A

Stalder #3UH Monroe, OH MHR 32.5 5,417 5,050 20

Rubel 1H Monroe, OH AR 31.1 5,183 6,554 N/A

Rubel 2H(2) Monroe, OH AR 30.9 5,150 6,571 N/A

Irons #4H Belmont, OH GPOR 30.3 5,050 6,629 23

AVERAGE 42.1 7,010 5,742 26.25

Source: Magnum Hunter Resources October 15, 2015 via PLS docFinder (www.plsx.com/finder)

EASTERN SCOUT

7 Completions; 317 Permits; 69 Rigs Running.

Eastern Scout April 11

Range drives efficiencies, high rates in AppalachiaRange Resources is primarily focused on its Appalachian division this year, where

it is seeing strong Marcellus rates and operational efficiencies. COO Ray Walker said the back half of the year should look good for growth in Appalachia as the company

brought only 20% of its expected wells online during Q1.The company drilled and completed a four-well pad in the super-rich

area of northwestern Washington County, although high IP rates caused the company to bring only two online because of capacity constraints in the gathering system. The pair averaged 31.4 MMcfe/d (69% liquids) each. Laterals averaged 10,772 ft, and the wells were completed in 54 stages. A three-well pad in the wet area averaged 35.3 MMcfe/d with 7,186-ft laterals. The pad was completed with 37 stages per well.

“These two pads illustrate the quality of our low-risk, long lateral inventory in Appalachia in the dry, wet and super-rich areas,” Walker said. “These results, when combined with going back onto existing pads with existing gathering and compression infrastructure, generate liquids-rich drilling economics that are among the best in the business.”

Range realized a number of drilling efficiencies during 1Q17. daily lateral footage drilled was up 67% versus the previous year, and it says it has drilled the longest Marcellus lateral in Pennsylvania. While it didn't give the specific length, Range said three of its 1Q17 wells were over 15,000 ft. COO Ray Walker attributes improvements to an upgraded rig fleet with higher horsepower and higher pressure rated equipment and more efficient equipment. Drilling costs per lateral foot are down 30%. About a third of the wells that will come online this year will be drilled from existing pads to save $200,000-$500,000 per well.

Washington County Marcellus wells average 31.4 MMcfe/d each.

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Volume 28, No. 06 3 e&PPowder River, Haynesville see resurgence

While the Permian Basin is the primary driver of US drilling activity and production, we’re taking a closer look in this issue at other notable plays and trends. The oily Powder River Basin (PG. 1) and gassy Haynesville (PG. 1) have both seen a spike in activity this year.

As Wood Mac analyst Robert Clarke pointed out at NAPE Summit, the Powder

River will be high on producers’ lists this year because it’s never cash flow negative with its high oil cuts and low breakevens (~$40/bbl). Chesapeake has just delivered its first Turner well (PG. 3), flowing over 2,300 boe/d, in a renewed program. EOG is also ramping up in the basin with 30 net completions on deck this year. Private player Massif is also flowing strong wells (PG. 21).

North Louisiana’s Haynesville was just bolstered by the USGS’ recent assessment that it contains a recoverable 304.4 Tcf—the largest-ever continuous natural gas assessment. Chesapeake, again, is one of the companies driving the renaissance with its “proppant-geddon” theory that has just yielded a 42.0 MMcf/d well in Caddo Parish.

But a handful of private players have routinely been among the most active in this play over the last year—Vine, Covey Park and Indigo Minerals. The first just filed for its IPO, spurring speculation that the others may follow. Vine has plans to ramp up to eight rigs this year with a 44-well program (PG. 2).

Among other unique trends, conventional producer Hilcorp made a transformative play for ConocoPhillips’ San Juan Basin position to become the largest private gas producer in the US (PG. 1). The usually tight-lipped company didn't offer specific plans, but it will apply the same successful formula to enhance aging fields as it does along the Gulf Coast. And EOG, finding value in EOR, has an accelerated 100-well EOR program planned in the Eagle Ford (PG. 5). Last year’s 32-well program yielded 300,000 bo.

Ark-La-Tex

IN THIS ISSUE

Haynesville contains 304 Tcf with 4.0 Bbo and 1.9 Bbbl of NGLs.

Chesapeake’s formula delivers better Haynesville wellsChesapeake is off to a strong start with its 2017 program. Aside from an impressive

first Turner well in the Powder River Basin (see story on PG. 1), the company continues to deliver monster IPs in the Haynesville, where new completion technology is driving better

rates and better economics. “This

is an absolute world-class resource for the company,” CEO Doug Lawler said. “We’ve done phenomenal things in the Haynesville.”

The company reported two new Haynesville wells that recorded high rates during 1Q17. The GLD 1H IP’d at 42.0 MMcf/d with an 8,200-ft lateral, improving on the ROTC 1H’s 40.0 MMcf/d rate from 4Q16. The Six J 1H flowed 35.0 MMcf/d with a 10,000-ft lateral during the quarter as well. Both are in Caddo Parish, Louisiana. Chesapeake estimates its breakeven is $2.35/Mcf in the play, and it has more than

1,200 drilling locations in the play.The company has led the recent

“proppant-geddon” in the Haynesville. Operators are testing anywhere form 3,000-5,000 lb of proppant per foot to deliver the kind of rates that Chesapeake is seeing. Its laterals are currently around 10,000 ft, but it is targeting 15,000-ft laterals toward the end of the year. Chesapeake is running three rigs in the play and will drill 30-35 wells.

In the Midcontinent, the company is focused on its oil-growth driver Oswego and the Wedge play. Ten recent Oswego wells have averaged IP-30s of 1,140 boe/d, yielding rapid and reliable oil growth for the company. The best of these wells was the Caldwell 22-18-6 1H, which flowed 1,813 boe/d (80% oil). Chesapeake estimates it gets 80% ROR at $50 oil on a D&C cost of $3.2 million with 400,000 boe EUR (83% liquids) in the Oswego. Chesapeake aims to bring 40-50 wells online in the Wedge while extending laterals, optimizing completions and testing spacing and new horizons. One of the best recent wells was the Hoskins 2H, a Meramec well that achieved a peak rate of 1,367 boe/d (65% oil) although this well doesn’t yet have 30 days of production.

Longer laterals, high-proppant use yielding wells over 40.0 MMcf/d.

Position flanks heavily developed core, with Bossier potential to south.

Oswego wells yield reliable growth, averaging IP-30 of 1,140 boe/d.

Chesapeake Flows Monster Wells in HaynesvilleGULF COASTTECHNOLOGY DRIVING RENAISSANCE

Continuing to deliver monster IPsGLD 1H – 42 mmcf/d, 8,200' lateral, 1Q 2017 TILSix J 1H – 35 mmcf/d, 10,000' lateral, 1Q 2017 TILROTC 1H – 40 mmcf/d, 10,000' lateral, 4Q 2016 TILCA 1H – 38 mmcf/d, 10,000' lateral , 2Q 2016 TIL

(1) PV10 positive breakeven price

ROTC 1HCA 1H

Six J 1H, GLD 1H

1,200+ locationsPost-divestiture and optimized for longer lateral development

<$2.35/mcf(1)

Breakeven

Source: Chesapeake March 28 Presentation via PLS docFinder www.plsx.com/finder

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■ Chaparral Energy set its 2017 capex at $135-155 million. While that is not an increase from 2016’s $150 million, the company will dedicate more capital to STACK development. Chaparral completed 16 new wells in 2016: 11 Meramec, two Oswego, two Osage and one Woodford. It achieved industry-leading D&C costs of $3.3 million per well in the Meramec.

■ While Earthstone Energy is investing a lot of energy into its new Permian position, the company also has plans this year for its legacy Eagle Ford asset. It will drill 11 wells in southwestern Gonzales County on capex of $23 million. Eight of the wells will sport 5,300-ft laterals, and three will sport 7,300-ft laterals.

■ Endeavor Energy Resources and newly formed Development Capital Resources (DCR) have entered into a $300 million Wolfcamp JV, according to Ares Management-backed DCR. The latter will fund the program as a non-op partner. DCR says two rigs are running in the program. DCR has also entered another $150 million DrillCo with an unnamed non-Permian operator.

■ EQT Corp. increased its Marcellus type curve 14% to 2.4 Bcfe per 1,000 ft of lateral. Improved recoveries are a result of larger frac jobs. The company will load 2,250 lb of proppant per foot this year, which is up from 1,550 lb per foot in 2015. Stage length is 200 ft, up from 170 ft in 2015. Laterals will average 8,000 ft, up from 7,000 ft last year.

■ Laredo has over 2,000 drilling locations that can accommodate 10,000-15,000-ft laterals. D&C costs are down $1.8 million from 2015 to $6.4 million per well for a 10,000-ft lateral. By extending its laterals, the company has found a 38% increase in ROR to ~55% and a 35% decrease in F&D costs to $6.26/bbl. The company also is doing the same amount of work with one rig today as it did with two rigs in 2014. By YE17, the goal is to have drilled 175,000 lateral feet in the year, up from 166,000 ft in 2016.

Drillbits

Better understanding of the geology and changes in drilling technology are credited for the increased estimate of technically recoverable resources.

“As the USGS revisits many of the oil and gas basins of the United States, we continually find that technological revolutions of the past few years have truly

been a game-changer in the amount of resources that are now technically recoverable,” said Walter Guidroz, coordinator of the USGS Energy Resources Program.

The USGS has been updating its assessments of other plays with a new review of the Marcellus underway. In December 2015, the agency doubled its estimate of the Barnett to 53 Tcf. Last summer, it increased its Mancos shale assessment to 66 Tcf, 74 MMbo and 45 MMbbl of NGLs from an initial 1.6 Tcf.

Haynesville regains traction among producers—The new USGS assessment bolsters a recent Haynesville resurgence. The

gas play is the US’ third largest gas producer behind the Marcellus (18.9 Bcf/d) and Permian (8.1 Bcf/d). The Haynesville is regaining popularity because of its advantaged location near the Gulf Coast and as producers have figured out how

to make the play’s economics work through the use of longer laterals and higher proppant loads.

Chesapeake has been touting the game-changing formula to increase Haynesville value since last summer. Laterals of 10,000 ft and higher proppant loads (some producers are loading up to 5,000 lb per lateral foot) have been delivering monster IPs for the company—anywhere from 35-45 MMcf/d (see PG 3).

“We’ve done phenomenal things in the Haynesville. This is an asset that at one point in time was thought dead by the industry,” CEO Doug Lawler said. “When we came back to the Haynesville and started testing new completion techniques and longer laterals, there were many that doubted the company, doubted our ability to drive greater value here. We’ve actually crushed all those doubts.” Exco and Comstock have followed suit on Chesapeake’s winning formula.

Private players are gearing up as well. Earlier this month, Vine Resources announced an IPO—the first of three private firms that have been driving activity in the play over the last year (see related story on PG 2). The rig count in the Haynesville is currently at 37, up from the teens throughout most of last year.

Ark-La-Tex

Haynesville, Bossier contain over 300 Tcf Continued From Pg 1

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Enhanced compeltions, long laterals drive resurgence.

Operators load up to 5,000 lb of proppant to yield high rates.

Vine running eight rigs in play this year as it gears up to go public.

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Volume 28, No. 06 5 e&PEOG accelerates Eagle Ford EOR program to 100 wells

After a successful 32-well Eagle Ford EOR program last year, EOG Resources will advance the program in 2017 with 100 additional wells across six areas in the Eagle Ford. The company’s 2016 EOR efforts doubled 2015’s 15-well pilot and delivered a net 300,000 bo (822 bo/d)—a 70% YOY increase in volumes. EVP Billy Helms said 2016’s

production was within 5% of EOG’s forecast and validated the strong results of 2015’s program.

EOG tested four pilots comprised of 15 wells across a

geologically diverse area in 2015, and the results were consistently positive and highly economic, Helms said. At the time, CEO Bill Thomas said the proprietary EOR technique was a technological breakthrough to increase value in the Eagle Ford. EOG said benefits included high incremental net present value and ROR on investment, low finding and operating costs, reduced severance tax rates, lower decline rates and increased recovery. In 2016, EOG moved to the larger 32-well pilot to test manufacturing-type scale of the program. "The pilot has been a success and confirms our initial results for field scale

implementation,” Helms said.The larger 2016 pilot was intended

to test how well the EOR technology could perform when implemented at field scale. The technique was applied to a variety of completion styles and spacing patterns ranging 200-500 ft on wells that were initially completed from 2011-2016. Results support EOG’s previous estimates that incremental recovery adds anywhere from 30-70% more resource to primary recovery estimates.

“This gives us further confidence as of the applicability of EOR across major areas of the field,” Helms said. “In addition, our technical understanding of this first-in-the-world EOR process is increasing.”

The 2016 pilot not only succeeded with resource recovery, but the economics work as well. The project supports EOG’s premium-well economics, which it characterizes as greater than 30% ATROR. Capital investment per well was $1.0 million, and funding costs were less than $6 per barrel.

South Texas ■ After pausing all D&C activity in 2H16,

Lonestar Resources is active again and plans to drill 12 net wells during 2017. The program

is already underway, and the company projected March volumes to average 5,500

boe/d—up ~1,000 boe/d from Lonestar’s Q4 average. Lonestar’s latest-generation completions have yielded 8% more cumulative production versus older wells at Burns Ranch in La Salle County, Texas.

■ Petro River Oil Corp. has spud the first of four vertical exploration wells in Osage County, Oklahoma. The first two

wells, South Blackland #1-11 and South Blackland 2-11, will be drilled to 2,800 ft TD. All four seek to test the first 1,610

acres of the 4,480-acre structural closures identified by new 3D seismic. Resource potential is 2.5 MMbo.

■ Petsec Energy expects first production from the platform at the Hummer Main Pass Block 270 in 3Q17. Initial capacity will be 50 MMcf/d and 1,000 bo/d to accommodate volumes from the discovery well, Main Pass 270

#3 BP 1. The well, located 50 miles

offshore Louisiana, initially tested at 19.88 MMcf/d and 396 bbl/d of condensate. It climbed from there but has been suspended while the platform is installed. Castex Offshore operates. Petsec holds 12.5% WI.

■ SM Energy’s RockStar acreage in Howard County draws all the attention, but the company continues to work in the Eagle Ford, too. SM is focusing on completing high-return wells in the play and drawing down its DUC inventory. It is also optimizing completions and its number of 10,000-ft laterals. In Webb County, SM brought six wells online spaced at 625 ft. They’re outpacing the company’s type curve for wells spaced at 900 ft even with a staggered Upper and Lower Eagle Ford pattern.

Drillbits

Ramping up from 2016’s 32-well pilot that produced 300,000 bo.

EOG Produced 300,000 bo On EOR Last Year

Successful 32-Well Pilot in 2016-Incremental Reserves 30%-70%-Well Spacing as Close as 200’

Test Supports Premium Economics -Direct ATROR* >30% and PVI** >2.0 -Capital Investment ≈$1MM per Well

2016 EOR Net Oil Production 300 MBO-70% Increase YOY

≈100 Additional Wells in 2017-Six Areas in Eastern Eagle Ford

Cumulative Oil Production per Well

1.0x

1.3x – 1.7x

Primary Recovery

(Net Mbo)

Enhanced Oil Recovery

Produce 2 - 5 Years Before EOR Injection

Production Response ≈3 Months After Injection

Source: EOG February 28 Presentation via PLS docFinder www.plsx.com/finder

EOR program supports premium-well economics (over 30% ATROR).

Regional Oil & Gas Intelligence November 5, 2015

Serving the local market with drilling activity, permits & deals for sale Volume 03, No. 15

DUVAL CO., TX PROPERTY3-Active Wells.SOUTH TEXAS PPProducing From Pettus & Yegua Y-21.100% OPERATED WI Available.Net Production: ~170-210 MCFD ~200Total Reserves: ~34 MBO & 22 BCF MCFDCONTACT SELLER FOR MORE INFOPP 5404RE

WANTED: EAGLE FORD PROJECTSNonOperated WI Investor. SOUTH TEXASInternational Petroleum Firm Wants To-- W--Participate as NonOperated WI Partner.Seeking Experienced Operators In Play.Budget of ~$10-$40 Million. NONOPOil or Liquids-Rich. W 5023DV

Deals For Sale

No Commission. Call 713-650-1212

All Standard Disclaimers & Rights Apply.

SOUTH TEXAS SCOUT

Sanchez’s Catarina Overview

Total Net Acres ~106,000 Average Working Interest 100% Average Net Revenue Interest 75% Planned Well Spacing (Acres) 75 – 100 Net Identified Drilling Locations 1,250 - 1,650 Gross Wells On Production 238 Awaiting / Undergoing Completions 27

EURs (MBoe) 600 – 700 D&C Costs ($MM) $4.5 F&D Cost ($ / Boe) $8.57 – $10.00 IRR @ $60 / Bbl & $3.75 / Mcf 35%+

LEF Well Economics

Acreage, Inventory & Operational Update

• Early results support stacked pay development in three

Western Catarina (~43,000 net acres)

Central Catarina (~26,000 net acres)

Eastern Catarina (~37,000 net acres)

Eagle Ford benches; Upper, Middle, & Lower Eagle Ford • Well performance currently exceeding high end

Catarina type curve through first year of development • Par�ally developed; Excellent offset operator results

• Early results in South-Central Catarina in line with the strongest to date in the asset: 30-Day IP Rates of nearly 1,350 BOE/D

• Expected further future development in South-Centralregion in 2016

• Explora�on area; full 3D seismic coverage; inversion processing in progress

• Early results ~50% above exis�ng wells in Eastern Catarina • Substan�al number of poten�al Lower Eagle Ford

drilling loca�ons

Western Catarina

Central Catarina

Eastern Catarina

Source: Sanchez Energy October 05, 2015 via PLS docFinder (www.plsx.com/finder)

Regional Activity (State Data)(10/13/15 to 11/02/15)

Compls PermitsSouth Texas (RRC 1) 60 73

South Texas (RRC 2) 39 83

South Texas (RRC 3) 2 13

South Texas (RRC 4) 8 37

Most Active Operators by Permits

➊ Marathon Oil 20

➋ Pioneer Natural Resources 15

➌ EP Energy E&P 13

Permits by Formation (by Last Scout)

Formation 11/05 10/15 09/24

Eagle Ford 143 205 151Wilcox 8 2 5Austin Chalk 6 14 8Buda 4 5 11Frio 3 1 –Vicksburg 3 2 –Barnsdall Sand 2 3 2Olmos 1 1 341-A & 98-A Cons 1 3 –Other Formations 35 52 59TOTAL 206 288 239Sources: TXRRC

Active Rigs Running (Baker Hughes) 96

SM’s Eagle Ford downspacing tests show promiseEagle Ford wells performed above type

curve for SM Energy in Q3, raising the company’s production in the shale 3% sequentially and 31% YOY to 134,500 boe/d—more than 75% of SM’s total production for the quarter across all plays and despite a decline in non-op Eagle Ford production. SM also reported successes in proving up additional drilling inventory with downspacing tests.

The company drilled multi-well pilot tests to determine downspacing potential and to add the Upper Eagle Ford to its

drilling inventory. Wells have been drilled in five of the nine planned pilot tests, with the remainder slated for 2016.

The initial test consisted of 14 wells on the gas-weighted eastern portion of SM’s acreage, downspaced to 450 ft

instead of its standard 625-ft spacing. Test 1 now has 130 days of sales and during Q3 reached a peak gas rate of 105 MMcf/d or 7.5 MMcf/d per well.

Sanchez’s Catarina development continues to outperformFor the third consecutive quarter,

Sanchez Energy’s Catarina project has been the driving force behind its Eagle Ford production. Strong well rates and accelerated development resulting from faster drilling times contributed to lower costs. The company’s results from the south central Catarina showed 30-day IP rates of ~1,350 boe/d.

Sanchez ran three operated rigs at Catarina during Q3 to bring 27

wells online. The 106,000-net-acre development area on the border of Dimmit and Webb counties, Texas, has been the focus of Sanchez’s operations

since it was acquired from Shell for $639 million in 2Q14. At the end of Q3, the company had 264 producing Catarina wells and 18 awaiting completion.

Efficiencies continued to help shave down well costs.

Q3 Eagle Ford production of 134,500 boe/d accounts for 75% of SM’s total.

Continues On Pg 3

Continues On Pg 5

93 Completions; 241 Permits; 95 Rigs Running

South Texas Scout April 7

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PetroScout 6 April 26, 2017

Ring exceeds pre-drill expectations in San AndresSince initiating its horizontal drilling program in Andrews and Gaines counties on

the Central Basin Platform last spring, Ring Energy has drilled 10 San Andres wells and increased its footprint from 8,000 to more than 63,000 net acres. The company now

has more than 825 (600 net) horizontal drilling locations in its inventory. “Our drilling inventory is such that we can stay very busy for a number

of years even if we choose to accelerate the program by adding additional rigs,” CEO Kelly Hoffman said. Ring has 22 horizontal wells planned this year, but Seaport Global Securities reports that management says the company is drilling faster and may see 30 wells this year. Seaport also says a second rig is being seriously considered for 2018. The play will see most of Ring’s $70 million capex.

Ring brought eight wells online so far in the program, exceeding internal expectations. Five 1-mile-lateral wells IP’d at 660 boe/d on average in 1Q17. One of the wells delivered

over 800 boe/d. These results compare with the 519 boe/d average 24-hour IP of the program’s initial three wells and exceed

Ring’s expectations. All are on track to average a net EUR over 59 boe per foot. Prior to launching the program, the company had expected the wells to recover a net 55 boe per foot.

Two of the wells are 1.5-mile laterals, one is 1.25-mile lateral, and the rest are 1-mile laterals. EVP Danny Wilson said the longer wells are showing preliminary net EURs of 35-55 boe per foot, which would yield 90-240% IRR at $45/bbl on a D&C cost of $2.4 million. The 1-mile laterals are tracking net EURs of 40-100 boe per foot. These would yield 70-500% IRR at $45/bbl on a D&C cost of $2.0 million.

Carrizo drilling six Wolfcamp A wells this yearWhile Carrizo is operationally focused on the Eagle Ford this year, the company

does plan to drill and frac six wells in Reeves and Culberson counties of the southern Delaware Basin, spending $30 million of its $560 million D&C capex. Carrizo currently is focused on the Wolfcamp A, which is more than 200 ft thick and has potential for

two landing zones. So far, the company has drilled eight wells in the basin.

Carrizo’s wells compare well with nearby peers. The company’s Fortress State 1H in Culberson County established its best 30-day rate at 1,520 boe/d (25% oil). A nearby 3ROC well, Wise West State 0703WA, yielded a 30-day rate of 1,399 boe/d (40% oil). At the recent IPAA OGIS conference in New York, Carrizo expressed an appetite to expand in the Delaware with Seaport Global Securities suggesting Austin-based 3ROC as a target because its assets directly offset Carrizo’s 23,500-net-acre position.

Yuma enters Permian Basin as an operator

Gulf Coast-focused Yuma Energy has entered the Permian Basin and will spud its first well in 2017. Targeting the San Andres play in Yoakum County, Yuma will be the operator of a joint development agreement with two private companies covering 33,280 acres. Yuma says there are 12 locations on the acreage and 3.0 MMboe in recoverable resource potential.

CEO Sam Banks said Yuma’s recent reverse merger with Davis Petroleum improved its financial position to allow for continued development of its Gulf Coast properties as well as its new Permian Basin position. Davis is now a wholly owned subsidiary of Yuma. Pro forma net production of Yuma averaged 2,445 boe/d for 4Q16, up 60% YOY.

In the Southeast, Yuma is generating value through recompletions and plans to spud the Glacier prospect targeting the Wilcox and Tuscaloosa sands in Livingston and St. Helena parishes this year. Operator PetroQuest successfully recompleted the Thibodeaux No. 1-ST1 well (12.5% WI) at Bayou Hebert field in Vermilion Parish, Louisiana, from the Lower Cris R-2 C sand to the Lower Cris R-2 B sand. The well is now producing 19.3 MMcf/d and 354 bo/d, up from 3.7 MMcf/d and 65 bo/d. The recompletion added significant volumes to the field, which is now producing 48 MMcf/d and 900 bo/d.

Yuma performed a workover on SL 18090 #2 in March at Lac Blanc field, returning the shut-in well to production. The well is producing 1.9 MMcf/d and 40 bo/d from the Miocene Siphonina D-1 (18,700 feet sand). Yuma notes that upside exists for 100 ft of net pay in the Deep Planulina prospect. Current production from this asset is 9.3 MMcf/d and 195 bo/d.

Permian

Will target San Andres in Yoakum County with first spud this year.

1Q17 wells average 660 boe/d IPs, up from 519 boe/d from fall program.

First HZ wells on track to average net EUR ~60 boe per foot.

Company looking to expand position in the Delaware.

Regional Oil & Gas Intelligence November 11, 2015

Serving the local market with drilling activity, permits & deals for sale Volume 03, No. 22

PERMIAN BASIN PROJECT 11 Producers. 2,200 Net Acres. (85% HBP)EDDY CO., NM YESO HORIZONTAL PLAY PP3 New Yeso Horizontal Wells Producing.Avg. 87% Operated WI; 67% NRIRecent Hz Yeso wells IP: 200 BOPD/Well3-Month Avg. Cash Flow: ~$246,000/MnOFFERS DUE NOVEMBER 11, 2015PP 4146DV

IRION CO., TX PROJECT 2,000-Gross/Net AcresMIDLAND BASIN - STACKED PAYSAcreage Is Contiguous and HBP. LHorizontal Wolfcamp A, B & C and ClineOffset By Devon and Broad Oak Energy.100% OPERATED WI; 75% NRIL 1071

Deals For Sale

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PERMIAN SCOUT

Pioneer’s Northern Spraberry/Wolfcamp Performance33 horizontal wells placed on production during Q3

– Majority were Wolfcamp B and Wolfcamp A wells

o Early production results from these wells are on average tracking >15% above a 1 MMBOE EUR type curve

– Remaining wells placed on production in Q3

o 2 Wolfcamp D wells with average 24-hour peak rate of ~1,600 BOEPD

o 1 Lower Spraberry Shale well that has not yet reached its 24-hour peak production rate

– 19 wells (17 Wolfcamp B & 2 Wolfcamp A) benefited from Pioneer’s completion optimization program

o Program includes optimizing stage length, clusters per stage, fluid volumes and proppant concentrations

o Early results from 26 completion-optimization wells placed on production during Q2 and Q3 are encouraging

100

500

1,000

2,000

0 30 60 90

Dai

ly P

rodu

ctio

n (B

OEP

D)

Days On Production

Q3 Wolfcamp A Average (2 Wells)

100

500

1,000

2,000

0 30 60 90

Dai

ly P

rodu

ctio

n (B

OEP

D)

Days On Production

Q3 Wolfcamp B Average (28 Wells)

1 MMBOE

800 MBOE

~8,700’ Average Perforated Lateral Length

1 MMBOE 800 MBOE

Updated End Oct

Updated End Oct ~8,400’ Average Perforated Lateral Length

Average 24-hr peak rate: ~1,800 BOEPD 84% oil content

Average 24-hr peak rate: ~1,900 BOEPD 78% oil content

Source: Pioneer Natural Resources November 03, 2015 via PLS docFinder (www.plsx.com/finder)

Regional Activity (State Data)(10/07/15 to 11/06/15)

Compls PermitsWest Texas (RRC 7C) 32 52

West Texas (RRC 8) 78 165

West Texas (RRC 8A) 12 22

Southeast New Mexico 17 83

Most Active Operators by Permits

➊ XTO Energy 26

➋ Pioneer Natural Res 22

➌ Apache Corp 15

Permits by Formation (by Last Scout)

Formation 11/11 10/28 10/14

Spraberry 103 124 95Wolfcamp 88 64 46Bone Spring 46 37 41San Andres 11 8 7Glorieta-Yeso 9 5 2Clear Fork 6 4 2Delaware 5 5 6Brushy Canyon 3 – –Devonian 3 3 6Other Formations 48 89 81TOTAL 322 339 286Sources: NMOCD & TXRRC

Active Rigs Running (Baker Hughes) 231

Two Pioneer Sale Ranch wells surpass 2,100 boe/dPioneer Natural Resources’ Sale

Ranch 23B #2H and 21C #3H had rates of 2,825 boe/d and 2,144 boe/d, respectively, targeting the Spraberry with the use of gas

lift. The wells averaged 2,484 bo/d and 2,068 Mcf/d (2,828 boe/d, 88% oil) and were drilled with laterals averaging 8,742 ft in Martin County’s Spraberry field.

Pioneer reported that it has shortened its average total time to drill, complete

and turn a three-well horizontal pad to production to 135 days in the Wolfcamp/Spraberry, and it has cut its average drilling time by seven days per well. The company

turned 33 horizontals to production in the Spraberry and

Wolfcamp during Q3, with 28 Wolfcamp B and two Wolfcamp A wells averaging peak production rates of 1,900 boe/d (78% oil). The Wolfcamp wells are tracking EURs of more than 15% above a type curve of 1 MMboe.

Q3 Wolfcamp wells avg. 1,900 boe/d, EURs 15% above 1 MMboe curve.

Continues On Pg 3

Continues On Pg 3

Parsley reports records, 1,638 boe/d Spraberry wellAn Upton County completion by

Parsley Energy flowed at a rate of 1,395 bo/d and 1,457 Mcf/d (1,638 boe/d, 85% oil) at full flow, according to Texas state data. The Shauna 9-16B #4415H was drilled in Spraberry field with a 7,195-ft lateral and fracked with 13,096,749 lb sand and 331,206 bbl frac fluid.

The company reported that one of its Wolfcamp B wells, the Taylor 45-33-4404H, set a company record with its 30-day IP rate of 1,504 boe/d on a 9,802-ft lateral. The nine

wells Parsley completed in Q3 averaged 30-day rates of 1,167 boe/d, also a company record. Those wells had average lateral lengths of 6,962 ft.

Parsley’s Ringo 10-7-4214H Wolfcamp A well, which was drilled as part of a two-well pad in Reagan County, set a Permian Basin record for the fastest lateral drilled. The well’s 7,128-ft lateral was drilled in 41 hours.

Wolfcamp B well had a company-record 30-day IP rate of 1,504 boe/d.

132 Completions; 288 Permits; 337 Rigs Running

Permian Scout April 26Increases production at Bayou Hebert

field with recompletion.

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Volume 28, No. 06 7 e&PPermian fits Marathon’s top-tier US strategy

Marathon Oil entered the Delaware Basin this spring and is already a significant player with 91,000 net acres in New Mexico over two quick acquisitions. The move adds a fourth core position in a top-tier unconventional play as the company increasingly shifts its strategy to low-cost, high-return US resource plays. Marathon plans to add a rig for a total of two this year and to double that for 2018.

Marathon is in a unique spot among US E&Ps. “We’ll now be the only E&P with material operations in the four best oil-rich plays in the

US—the Permian, STACK and SCOOP, the Bakken and Eagle Ford,” said CEO Lee Tillman. The second deal added 440 operated drilling locations to Marathon’s arsenal, bringing the total to more than 1,000 locations with risked resource potential of 580 MMboe. Altogether, Marathon now has 2,650 gross-operated locations when assuming tighter density (34 wells per section) and secondary targets. The base case assumes six target benches, but the company is eyeing up to 10 over 5,000 ft of stacked pay.

The rapid rate of change in the northern Delaware drove the decision. Over the last three years, 180-day cumulative volumes in Lea and Eddy counties, New Mexico, are up over 100% as proppant load has climbed from a little over ~500 lb per foot in 2013 to more than 2,000 lb per foot today. And it is still early for completion evolution, operations EVP Mitch Little noted.

“As the saying goes, rigs don’t lie, and there are over 30 rigs drilling Eddy and Lea counties right now, with recent results expanding the core of the play in nearly every direction,” Little said of the impressive northern part of the basin.

Marathon highlighted IP-30s across the two counties ranging 1,600-3,600 boe/d in the Wolfcamp and 1,700-2,400 boe/d in the Bone Spring. Oil cuts average 80%. Companies are also producing good results in secondary targets such as the Avalon, Brushy Canyon and Yeso. Of particular note were EOG’s Leghorn 32 State 201H, which targeted the Avalon and produced an IP-30 of 3,630 boe/d (70% oil) with only a 4,500-ft lateral, and Endurance’s White Falcon 16 1H, which tapped the Brushy Canyon to yield an IP-30 of 1,813 boe/d (88% oil) with a 4,000-ft lateral.

Permian ■ Torchlight successfully tested the

Flying B Ranch #2 vertical well in the Lower Wolfcamp A and Upper Wolfcamp B, confirming a second horizontal bench in the Hazel project in the Midland Basin. Next up, the well will test the Leonard interval in June to prove up a third bench. The well will be fracked and turned to sales. It will be the first horizontal test in the project. The lateral will be 7,500 ft. CEO John Brda said, “This test validates our theory that commercial production of oil and gas from horizontal development in multiple stacked pay zones across different areas of our lease is achievable.”

■ Total E&P USA Oil Shale has left its JV with Utah-based Red Leaf Resources. The 10,000 bo/d project at

Seep Ridge in eastern Utah was to be the first commercial project of Red Leaf’s EcoShale

technology but is still in the permitting stages, according to Red Leaf’s website. The JV was formed in spring 2012. Red Leaf says it is considering options for continued development of Seep Ridge, which is estimated to contain 120 MMbo. The JV also contained the Holliday block, which contains an estimated 479 MMbo.

Drillbits

Marathon Illustrates Northern Delaware’s Increasing Rates

0

500

1,000

1,500

2,000

2,500

3,000

2013 2014 2015 2016

Prop

pant

lb/ft

• Northern Delaware industry well performance consistently improving year over year

– 180 day cumulative production increased >100% in three years

– Outpacing other basins on rate of change

• Uplifted well results correlated to increased completion sizes

• Outstanding Wolfcamp and Bone Spring economics

– >90% IRRs at flat $55 WTI

– Early stages of D&C technical advancements

Average Hz Well Performance (Lea & Eddy Co. NM)

0

30,000

60,000

90,000

120,000

150,000

2013 2014 2015 2016

Cum

ulat

ive

(BO

E)

90d Cum. Prod. 180d Cum. Prod.

Completion Intensity Over Time (Lea & Eddy Co. NM)

Size of bubbles illustrate 180d cumulative production

Source: Marathon Oil March 27 Presentation via PLS docFinder www.plsx.com/finder

Four rigs in early 2018 as Marathon initially targets six benches.

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PetroScout 8 April 26, 2017

EAST TEXASEAST TEXAS PROSPECTS~3,500-Acres. ~20-Locations Available.ROBERTSON COUNTYGOLDEN LANE OF REEFS DVObjectives: Buda, Woodbine, CottonValley & Pinnacle Reef COTTON100 Sq Miles Of Excellent 3D Seimic VALLEYOver Analog Major Discoveries & Prospects100% OPERATED WI; 75% NRILow Risk/ High Reward OpportunityPotential Reserves: 1 TCFDV 4682

NORTH LOUISIANACLAIBORNE PH., LA PROSPECT240-Gross/Net Acres; 4-Potential Wells.NORTH LOUISIANAObj 1: 4,050’ Sand DVObj 2: 4,200’ Sand2D Seismic, Subsurface Geology ---- Geophysical Data Available.45.23% Non-Operated WI; 75% NRI NORTHObj 1 IP Rates: 150 BOPD Per Well LOUISIANAObj 2 IP Rates: 150 BOPD Per WellEst Well Reserves: 292 MBO Per WellEst Project Reserves: 1.2 MMBODHC: $400,000; Completion: $415,000DV 3856

RAPIDES PH., LA LEASEHOLD32,303-Contiguous Net Acres. LTUSCALOOSA MARINE SHALELEASEHOLD FOR SALE TMS5-Years Remaining Term.L 2615

ALABAMACLARKE CO., AL PROSPECT613-Net Acres. 1-Proposed Well.ALABAMA GULF COAST DVTargets: Smackover & Norphlet At 14,500’3D Seismic Data AvailableDelivering An Average 76% NRI SMACKOVERProposed Well Offsets Oil Test.Estimated Potential Reserves: 882 MBODHC: $2,200,000; Completion: $750,000DV 3862

COVINGTON CO., AL PROSPECT400-Total Acres. 2-Potential Wells.EASTERN GULF COAST BASINObj 1: Frisco City At 11,500 Ft. DVObj 2: Smackover At 11,600 Ft.3D Seismic, Subsurface Geology & ---- Geophysics Data Available SMACKOVER50% OPERATED WI; 75% NRIEst Net Reserves: 500 MBO & 1 BCF/WellDHC: $1,000,000; Compl: $350,000.DV 4451

ARKANSASMILLER CO., ARKANSAS PROSPECT2 Wells Drilled.PILL BRANCH FIELDJeter 1 & 2 Lime Targets DVFossiliferous & Oolitic Tidal ShoalsTarget Depth ~6,000 Ft.Core Data and Production Tests SEEKINGSEEKING JV PARTNER PARTNERExpected Well IP: ~40 BOPDOffsetting Wells Avg ~100 MBO (49 Wells)Est Well EUR: 75 MBO/WellPotential Reserves: 1.4 MMBODHC: $250,000; D&C Costs: $600,000DV 8829

UNION CO., AR PROSPECT434-Acre Deal Defined By 3 Wells.SMACKOVER SHORELINEProspect Identified By 3 Wells. DV2D Seismic Interpreted.100% OPERATED WI AVAILABLE SMACK-Potential Reserves: 1.05 MMBO OVERDHC: $624,000; Completion: $472,000DV 3286

EAST TEXASEAST TEXAS HAYNESVILLE PROSPECT11,377-Gross Acres. 10,151-Net Acres.ANGELINA & NACOGDOCHES CO., TX DVTargets: Haynesville & BossierLeasehold Can Deliver 75% NRI HAYNESVILLEPrimary Term Exp: Nov 2018 - Jan 2019 2-Yr Option To Extend Exp. 2020 - 2021DV 4362

EAST TEXAS MINERALS FOR LEASE5,200-Gross Mineral Acres. 3,650-NMA.ANGELINA COUNTY LEAST TEXAS AREAMinerals Available Through Surface to MINERALSTravis Peak. LEASEOPEN ACREAGE AVAILABLE FOR LEASELEASE TERMS NEGOTIABLEL 4477

NACOGDOCHES CO., TX MINERALS160-Gross & Net Mineral Acres.EAST TEXAS LObjectives: Cotton Valley, Travis Peak,Haynesville/ Bossier ARKLATEXMINERALS FOR LEASEL 4654M

PANOLA CO., TX LEASEHOLD~3,354-Acres. LDEEP RIGHTS ONLYTargeting The Haynesville Shale DEEPDepths Below Cotton Valley RIGHTSAcreage Contiguous & Held By ProductionLeases Can Deliver 75-81% NRI.L 2632

FLORIDASOUTH FLORIDA EXPLORATION~150,000-Seismic Option Acres.HENDRY & COLLIER COUNTIESSOUTH FLORIDA BASIN EXPrimary Obj: U. Sunniland & L. CretaceousSecondary Obj: Dollar Bay, Twelve Mile,Pumpkin Bay, Bone Island & Wood RiverProposed Depth: ~12,000 Ft. UPPER25% NonOperated WI; 77.5% NRI SUNNILANDWell Reserves: 800 MBO/Well25% WI - DHC: $799,000; Compl: $352,350EX 9055

MISSISSIPPIMISSISSIPPI TMS PROSPECT21,361-Gross Acres. 14,886-Net Acres.AMITE & WILKINSON COUNTIESTUSCALOOSA MARINE SHALE DVObj 1: Tuscaloosa Marine Shale.11,500 Ft.Obj 2: Wilcox SandsExpected IPs: 400-1,200 MBO/Well OIL100% OPERATED WI; 75% NRI WINDOWOffsets Goodrich, Encana, Comstock,-- and Sanchez Production.Almost All Leases Have A Primary ---- 3 Yr Term with 2 Yr Extension.DV 3511L

MULTIPLE TEXAS GULF COASTTEXAS & LOUISIANA PROPERTIESMultiple Properties.GULF COAST CONVENTIONALPredominantly Operated 70% Avg WI PPCurrent Production: ~8,000 BOEDEst Jan 2017 Cash Flow: $3,800,000 ~8,000Proved Reserves: 61,481 MBOE BOEDTotal Proved PV10: $533,203,000Assets Marketed In Four Distinct PackagesCONTACT AGENT FOR UPDATEPP 2110PKG

SOUTH LOUISIANAALLEN PH., LA PROSPECT2-Potential Wells.GULF COAST ONSHORETargeting 5,400 Ft. Upper Sand DVTotal Vertical Depth 6,000 Ft.Strat Trap w/3D Conforms To Well Control--- Amplitude GULFLeases Can Deliver 71% NRI COASTEstimated IP Rates: 150 BOPD & 30 MCFDShelf Energy LLC To OperateUnrisked Rsrvs: 1,270 MBO & 978 MMCFLease Expirations In 2020.DHC: $953,500; Compl: 476,900DV 2812

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Volume 28, No. 06 9 e&PUS Industry Activity as of April 21 Crude Production by State (bo/d)

State Rigs Jan-17 Dec-16Alabama 2 21,000 22,000 Alaska 6 516,000 519,000 Arizona 0 0 0Arkansas 1 14,000 14,000 California 9 485,000 492,000 Calif. Offshore 0 14,000 13,000 Colorado 29 298,000 294,000 Florida 0 5,000 5,000 GOM 20 1,748,000 1,729,000 Hawaii 0 0 0Idaho 0 0 0Illinois 2 22,000 23,000 Indiana 0 5,000 5,000 Kansas 0 93,000 94,000 Kentucky 0 6,000 12,000 Louisiana 39 140,000 142,000 Michigan 0 15,000 15,000 Mississippi 2 51,000 54,000 Missouri 0 0 0Montana 0 58,000 58,000 Nebraska 0 6,000 6,000 Nevada 0 1,000 1,000 New Mexico 58 417,000 419,000 New York 1 1,000 1,000 North Dakota 44 974,000 940,000 Ohio 22 51,000 45,000 Oklahoma 124 391,000 404,000 Pennsylvania 34 16,000 16,000 South Dakota 0 4,000 3,000 Tennessee 0 1,000 1,000 Texas 425 3,195,000 3,154,000 Utah 8 82,000 84,000 Virginia 0 0 0West Virginia 12 22,000 21,000 Wyoming 19 186,000 188,000 Total 857 8,838,000 8,774,000

3

2

16

15

0

01

8

00

0

10

$0

$15

$30

$45

$60

$75

250

750

1,250

1,750

2,250

Apr-15 Aug-15 Dec-15 Apr-16 Aug-16 Dec-16 Apr-17

Rig Count WTI

US National Rig CountOil: 688 rigsGas: 167 rigsMisc: 2 rigs

Total: 857 rigs

1

US rig count rises again for 14th week in a row

The US oilpatch saw another 10-rig gain in the week ending April 21 for a total of 857 rigs. Since last May’s low of 404 rigs, US producers have added 453 drilling rigs. This week’s gain was split evenly between gas and oil rigs. Gains were seen in the Eagle Ford with three new rigs while one rig each was added in the Permian, Niobrara, Barnett, Granite Wash, Marcellus and Williston. The Permian now has 340 rigs running followed by the Eagle Ford with 78 rigs. The Cana Woodford is third with 51 rigs. The Williston Basin has 44 rigs.

-2

Source: Baker Hughes

30-Day Rig Count & Change (Number, +/- as of 04/21/17)

19

44

9

425

0

029

58

80

1

39 -32 2

22 134

00 1

12

20

02

-26

0

0

0

0

124

Month/Year 04-17 04-16 04-15 04-14

US Rig Count 857 431 932 1,861

US Rig Count by Basin

Play New Last%

Chg

Barnett 6 5 20%

DJ-Niobrara 25 23 9%

Eagle Ford 78 73 7%

Fayetteville 1 1 0%

Granite Wash 10 14 -29%

Haynesville 37 38 -3%

Marcellus 46 44 5%

Mississippian 8 6 33%

Other 176 178 -1%

Permian 340 319 7%

Utica 23 22 5%

Williston 44 42 5%

Woodford 63 59 7%

Grand Total 857 824 4%

Sources: Baker Hughes

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PetroScout 10 April 26, 2017

Southeastern Scout (Last Scout: 03/27/17 to 04/17/17)

Permits Compls

State/Region (Number/change)

Alabama 7/4 -/-

Florida -/- -/-

Mississippi 6/-4 2/-

South Louisiana 3/-10 20/-9

Southeast TX (RRC 3) 40/-1 17/7Gulf of Mexico 25/3 -/-

New Permits by Formation

Formation 04/20 03/30 03/09

Woodbine 6 4 -

Eagle Ford 4 7 9

Austin Chalk 3 3 1

Pottsville 2 1 1

Smackover 2 1 1

Buda 1 2 1

Chandler 1 - -

Cotton Valley 1 1 19

Paluxy 1 1 -

Other 60 69 143

TOTAL 81 89 175

Top Counties by New Permits

County State Perm. BHI Rigs

Mississippi Canyon GOM 8 5Madison RRC 3 7 2Green Canyon GOM 6 6Brazos RRC 3 5 1Hardin RRC 3 4 -Liberty RRC 3 4 -

Top Operators by New Permits

Operator 04/20 03/30 03/09

Hawkwood Energy 6 1 -

Shell 6 5 4

Apache Corp 4 - 3

Quail Creek Oil 4 - -

Top Counties by Rig Count

County State 04/14 03/30 03/03

Green Canyon GOM 6 6 7Mississippi Canyon GOM 5 2 1

Burleson RRC 3 4 3 3

Walker Ridge GOM 3 4 4

SOUTHEASTERN 45 44 42

Sources: BHI, AL OGB, BOEM, FL DEP, MSOGB, SONRIS & TX RRC

Midcontinent Scout (Last Scout: 03/31/17 to 04/17/17)

Permits Compls

State/Region (Number/change)

Nebraska 1/-8 -/-

Kansas 43/-21 61/-13

Oklahoma 74/-19 68/-23

North Texas (RRC 5) -/-3 4/4

North Texas (RRC 7B) 19/-5 10/3North Texas (RRC 9) 19/3 9/-

TX Panhandle (RRC 10) 17/2 6/-

New Permits by Formation

Formation 04/19 04/15 03/22

Mississippian 31 28 40

Cleveland 8 9 8

Arbuckle 7 9 8

MSSPN & WDFD 7 8 6

Big Lime & Oswego 6 3 1

Woodford 6 7 12

St. Louis 5 1 3

Caddo 4 2 2

Squirrel 4 21 13Other 95 136 124

TOTAL 173 224 217

Top Counties by New Permits

County State Perm. BHI Rigs

Kingfisher OK 16 19

Grady OK 11 12

Hutchinson RRC 10 10 -

Blaine OK 6 24

Top Operators by New Permits

Operator 04/19 04/15 03/22

PG-M International Op 8 - -

Cimarex Energy 7 5 1

Chesapeake 6 8 8

Jones Energy 5 7 5

Linn Operating 5 - -Merit Energy 5 1 3

Top Counties by Rig CountCounty State 04/14 03/31 03/17Blaine OK 24 23 25

Kingfisher OK 19 19 17

Grady OK 12 10 9

Garvin OK 9 8 8Canadian OK 8 8 7

MIDCONTINENT 141 136 128

Sources: BHI, KS KCC, NOGCC, OK OCC & TX RRC

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Eastern Scout (Last Scout: 03/06/17 to 04/06/17)

Permits Compls

State/Region (Number/change)

Illinois 26/14 -/-

Indiana 8/- 6/6

Kentucky 8/1 -/-

Michigan 9/5 -/-

New York 1/-1 -/-1

Ohio 134/49 -/-

Pennsylvania 73/10 -/-

Tenessee -/-9 -/-

West Virginia 58/-11 1/1

New Permits by FormationFormation 04/11 03/21 02/28

Utica-Point Plesant 55 36 42Marcellus 39 49 44Trenton-Black River 27 5 -Point Pleasant 21 12 13Clinton 18 19 7Ft. Payne 11 2 1Knox 6 12 6Berea 5 5 2Cypress 4 - 6Other 131 119 185

TOTAL 317 259 306

Top Counties by New Permits

County State Perm. BHI RigsBelmont OH 48 8Jefferson OH 17 3Ritchie WV 17 1White IL 13 1Carroll OH 13 1

Top Operators by New Permits

Operator 04/11 03/21 02/28Rice Drilling D LLC 39 20 11Antero Resources 32 11 17Chesapeake 29 15 3EQT Production 19 26 55Ascent Resources 13 10 21

Top Counties by Rig CountCounty State 04/07 03/17 02/24Washington PA 10 9 9Belmont OH 8 8 9Monroe OH 7 7 6Greene PA 6 6 6Susquehanna PA 6 6 6

EASTERN 69 66 64Sources: BHI, DNR IL, DNR IN, KYEEC, MI MDEQ, NYSDEC, ODNR, PADEP, TDEC & WVDEP

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Volume 28, No. 06 11 e&PArk-La-Tex Scout (Last Scout: 03/20/17 to 04/10/17)

Permits Compls

State/Region (Number/change)

Arkansas 3/1 26/11

North Louisiana 42/6 43/24

East Texas (RRC 5) 8/-6 3/-1

East Texas (RRC 6) 37/13 16/5

New Permits by Formation

Formation 04/13 03/23 03/02

Haynesville 38 30 21Cotton Valley 10 10 5Pettit 8 3 3Wilcox 5 3 2Travis Peak 4 7 2Barnett 2 10 -Holt Bryant 2 2 2Fayetteville 2 - 5Fredricksburg 2 - -Other 17 11 33

TOTAL 90 76 73

Top Counties by New Permits

County State Perm. BHI Rigs

DeSoto NLA 21 19Panola RRC 6 11 1Rusk RRC 6 6 2San Augustine RRC 6 5 6Grant NLA 4 -Gregg RRC 6 4 -

Top Operators by New Permits

Operator 04/13 03/23 03/02Indigo Minerals LLC 13 2 -XTO Energy 9 2 2Sheridan Production 7 5 1Chesapeake 6 4 -BP America 5 3 3Tanos Exploration 5 2 1

Top Counties by Rig Count

County State 04/07 03/17 02/24DeSoto NLA 19 18 15Lincoln NLA 6 6 5San Augustine RRC 6 6 6 6Red River NLA 5 5 5Cherokee RRC 6 4 4 2Henderson RRC 5 2 1 1

ARK-LA-TEX 55 55 52

Sources: BHI, AOGC, SONRIS & TX RRC

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Permian Basin Scout (Last Scout: 03/06/17 to 04/07/17)

Permits Compls

State/Region (Number/change)

West Texas (RRC 7C) 38/5 18/7

West Texas (RRC 8) 235/-42 54/-1

West Texas (RRC 8A) 36/4 32/9

SE New Mexico 45/9 24/11

New Permits by FormationFormation 04/12 03/29 03/15Wolfcamp 89 87 138Spraberry 88 150 125Bone Spring 37 41 53San Andres 16 15 14Clear Fork 14 5 13Pennsylvanian 13 - 3Wolfbone 11 12 9Devonian 8 2 1Delaware 5 6 2Other 73 60 106

TOTAL 354 378 464

Top Counties by New Permits

County State Perm. BHI Rigs

Reeves RRC 8 54 50Lea SENM 28 22Midland RRC 8 26 38Ward RRC 8 25 6Martin RRC 8 21 25

Top Operators by New Permits

Operator 04/12 03/29 03/15

Anadarko E&P 22 17 21Parsley Energy 16 10 7Apache Corp 15 24 24COG Operating 14 20 16Occidental 14 16 24

Top Counties by Rig Count

County State 04/07 03/24 03/10

Reeves RRC 8 50 48 47Midland RRC 8 38 36 40Loving RRC 8 29 28 30Eddy SENM 26 25 25Martin RRC 8 25 19 19

PERMIAN BASIN 328 312 306

Sources: BHI, NMOCD & TX RRC

Drilling & Permit Data Visit: www.plsx.com/regionalsVisit: www.plsx.com/regionals

Eastern Scouttracks the Marcellus, Utica and other legacy plays.legacy plays.

Southeastern Scouttracks the Tuscaloosa Shale and legacy conventional plays.conventional plays.

MidContinent Scouttracks the Mississippian, Granite Wash, Woodford and other plays.WoodWW foff rd and other plays.

Ark-La-Tex Scouttracks Fayetteville, Haynesville and other traditional ETX plays.other traditional ETX plays.

Permian Scouttracks the Permian Basin and other new and legacy plays.g y p y

South Texas Scouttracks the Eagle Ford and other new and legacy plays.and legacy plays.

Bakken Scouttracks Bakken, Three Forks and other new and legacy plays.

Western Scouttracks Niobrara, Four Corners and Western US plays.

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PetroScout 12 April 26, 2017

South Texas Scout (Last Scout: 03/13/17 to 03/31/17)

Permits Compls

State/Region (Number/change)

South Texas (RRC 1) 114/17 42/3

South Texas (RRC 2) 91/-56 35/-4

South Texas (RRC 3) 11/-7 1/-

South Texas (RRC 4) 25/10 15/2

New Permits by Formation

Formation 04/07 03/16 02/23

Eagle Ford 159 218 176Austin Chalk 15 10 17Olmos 4 - 441-A & 98-A Cons 3 11 19San Miguel 3 - 4Buda 2 2 5Woodbine 2 1 1Yegua 2 - -Wilcox 1 4 1Other 50 31 47

TOTAL 241 277 274

Top Counties by New Permits

County State Perm. BHI Rigs

Karnes RRC 2 47 20Dimmit RRC 1 32 9La Salle RRC 1 24 10DeWitt RRC 2 19 5Gonzales RRC 1 14 3

Top Operators by New Permits

Operator 04/07 03/16 02/23

Chesapeake 29 35 15EOG Resources 17 21 30Burlington Resources 15 37 10Hilcorp Energy 12 17 26SN EF Maverick LLC 12 - -

Top Counties by Rig Count

County State 03/31 03/10 02/17

Karnes RRC 2 20 19 15La Salle RRC 1 10 7 6Dimmit RRC 1 9 10 10Webb RRC 4 7 7 8

SOUTH TEXAS 95 85 79

Sources: TX RRC & BHI

Bakken Scout (Last Scout: 04/01/17 to 04/20/17)

Permits Compls

State/Region (Number/change)

Montana 2/-5 1/-1

North Dakota 142/14 18/-14

South Dakota -/- -/-

New Permits by Formation

Formation 04/25 04/04 03/14

Bakken 31 18 12Three Forks B1 17 20 38M Bakken 16 31 29Three Forks 12 25 12Three Forks B2 3 4 3Dakota 1 2 -Other 64 35 61

TOTAL 144 135 155

Top Counties by New Permits

County State Perm. BHI Rigs

McKenzie ND 71 23Mountrail ND 34 5Williams ND 26 8Dunn ND 4 7Divide ND 3 -Roosevelt MT 2 -

Top Operators by New Permits

Operator 04/25 04/04 03/14

Continental Resources 20 9 11Sinclair O&G 14 8 -Whiting O&G 14 23 34XTO Energy 14 - -Oasis Petroleum 12 17 5

Top Counties by Rig Count

County State 04/21 03/31 03/10

McKenzie ND 23 18 18Williams ND 8 7 5Dunn ND 7 10 10Mountrail ND 5 5 2Stark ND 1 1 1

BAKKEN 44 42 38

Sources: BHI, MBOGC, NDIC & SDDNR

Western Scout (Last Scout: 03/18/17 to 04/11/17)

Permits Compls

State/Region (Number/change)

California 72/-123 -/-

Colorado 246/-16 71/-

Nevada -/- -/-

NW New Mexico 5/- -/-1Utah 17/-7 4/-

Wyoming 411/167 13/-12

New Permits by Formation

Formation 04/18 03/28 03/07

Niobrara 266 213 344Codell 92 57 158Turner 48 15 64Frontier 46 48 52Lance 43 30 9Mowry 35 29 23Iles 33 20 -Williams Fork-Iles 25 1 -Kern River 23 20 30Other 140 297 262

TOTAL 751 730 942

Top Counties by New Permits

County State Perm. BHI Rigs

Converse WY 170 6Weld CO 140 21Laramie WY 97 2Campbell WY 68 1Kern CA 49 6

Top Operators by New Permits

Operator 04/18 03/28 03/07

EOG Resources 152 - 114Ultra Resources 43 30 -Anschutz Oil 42 42 96Whiting O&G 42 14 -Anadarko E&P 40 18 205

Top Counties by Rig Count

County State 04/14 03/24 03/03

Weld CO 21 24 20Sublette WY 7 7 7Converse WY 6 6 5Kern CA 6 6 3Garfield CO 5 5 4

WESTERN 66 64 57

Sources: BHI, COGCC, DOGGR, NDOM NV, NMOCD, UDOGM & WOGCC

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Volume 28, No. 06 13 e&PSOUTHEAST TEXAS

EAST TEXAS MINERALS FOR LEASE32,700-Gross Mineral Acres. 23,100-NMA.TRINITY & POLK COUNTIES LPrimary Objectives: Austin Chalk &Woodbine Formations AUSTIN CHALKMINERALS FOR LEASEL 3001

GALVESTON CO., TX PROSPECT2-PUDS; Multiple Wells and TargetsALTA LOMA E. FIELDFRIO TREND DVMiddle & Lower Frio Sands.Depths Range from 12,000-14,500 Ft.Proprietary 3-D & Subsurface Control. PUD / 3D50% NonOperated WI; 75% Lease NRIAcreage Under Lease or HBP by OperatorInitial PUD EUR: 230 MBC & 4.6 BCFProject EUR: 1.56 MMBC & 32 BCFD&C Costs: $3.9MM; Reentry $1.5MMDV 2134

JACKSON CO., TX PROSPECT200-Acres. 1-Potential Well.TEXAS GULF COAST DVObjective: Yegua. 5,700 Ft.3D Seismic Data Available~30% OPERATED WI; 75% NRI FRIOExp IP(Yegua): 35 BCPD & 600 MCFDEst Well Reserves: 45 MBC & 1.5 BCFDHC: $398,000; Completion: $225,000DV 2655

LIBERTY CO., TX PROSPECT600-Acres. 5-Potential Wells.TEXAS GULF COASTObj 1: Upper Wilcox. 8,900 Ft. DVObj 2: Middle Wilcox. 10,200 Ft.2D Seismic, Subsurface & GeophysicsTerms Negotiable & Operations Available100% OPERATED WI; 75% NRI WILCOXOffset Oil IP: 50-120 BOPDOffset Gas IP: 500-2,000 MCFDEst Reserves/Well: 140 MBO & 1.0 BCFEst Rsrvs/Project: 700 MBO & 5.0 BCFDHC: $700,000; Compl: $1,200,000DV 8452

MATAGORDA CO., TX PROSPECT136 Acre Four Way Closure.UPPER FRIO OIL TREND DVMultiple Targets Proven Productive On TrendPotential Target Depth: 10,000 Ft.Normal Pressure. Non-Pipe. FRIO3D Seismic Data and Well Control TRENDLEASE WILL DELIVER 75% NRIPotential Well IP: 300 BOPD8 Month Payout. ROI: 8.1 to 1.Potential Reserves: 1.4 MMBODHC: $744,000; Completion: $506,000DV 2948

SOUTH LOUISIANAWASHINGTON PH., LA REENTRY1-Re-Entry Well. 640-Acres.SOUTH LOUISIANA - GULF COASTRodessa, Mooringsport, Fredricksburg RE& Tuscaloosa ZonesE-Log & NuTech Log Supported REENTRY75% WORKING INTEREST AVAILABLERecoverable Rsrvs: 200 MBO & 8-15 BCFCONTACT OWNER FOR MORE INFORE 2756DV

SOUTH TEXASJACKSON CO., TX PROSPECT80-Acres.SWAN LAKE FIELDLOWER FRIO OIL DVPrimary Obj: Frio At 8,700’ Sand3D Seismic & Subsurface Geology30% WI AVAILABLE; 74% NRIEstimated Production: 120 BOPD FRIOProven Highside Closure.80’ High To Cond. FT’s & Cores.Potential Reserves: 316 MBO & 833 MMCFG&G, Land & Seismic: $80,000Drilling: $600,000; Compl: $400,000DV 1343

JACKSON CO., TX PROSPECT~200-Acres.SOUTH TEXAS - GULF COAST DVCook Mountain & Yegua At 12,500 Ft.40% Working Interest; 75% NRI GULFPotential Reserves: 2.6 MMBO & 53 BCF COASTEst Drill & Complete Costs: $2,640,000DV 2039

LA SALLE CO., TX PROSPECTLarge Acreage Position: 18,000+ Acres.SOUTH TEXAS LTargeting: Horizontal Olmos, Eagle Ford-- Austin Chalk, Buda & Wilcox EAGLEACREAGE FOR LEASE - 75% NRI FORDL 9411DV

STARR CO., TX PROSPECTEst 14-QC Wells. 2,362-Acres.MULTI-ZONED STACKEDObj 1: QUEEN CITY At 9,200 Ft. DVObj 2: Wilcox At 11,500 Ft.Obj 3: Cook Mtn - 6,500’ & Yegua - 5,000’New 2D Seismic & Geologic MappingParadise Software Identifies Hot Spots.AVO Type 2P Matches Prolific Analog Wells 89Est IP(30): 2.5 MMCFD & 65 BO BCFEEst QC Resource: 2,000 MBO & 77 BCFPer Well Resource: 143 MBO & 5.5 BCFPV10 (Strip): $85,000,000Up To 3 Units In Block A & B Available: Blk A: 29.17% WI BPO - 25% APOBlk B: 23.3% WI; Operations NegotiableDV 4575

SOUTH LOUISIANABEAUREGARD PH., LA PROSPECT1-Prospect. 760-Acres.GULF COAST BASINMultiple Cockfield/Yegua Sands. 8,200 Ft. DV3D Seismic, Subsurface Geology-- and Geophysics Data Available.50% OPERATED WI; 75% NRI YEGUAExpected IP Rate: 250 BOPDEst Well Reserves: 350 MBOEst Project Reserves: 4.0 MMBODHC: $892,000; Completion: $701,000DV 2145

CALCASIEU PH., LA ASSETS130+ Wells. 1,916-Net Acres. 478-NMA.VINTON FIELD>50 Behind Pipe & Rework Well Candidates PPSeismic Owned & Available ReprocessingAvg 98.93% OPERATED WI; 79.7% NRI6-Mn Gross Production: 247 BOPD GULFUpside Potential: >800 BOPD In ReWork COAST6-Mn Avg Net Income: $137,138/MonthAGENT WANTS OFFERS MAY 4, 2017PP 3166DV

GULF COAST SALT DOME Producing Wells Plus Upside.SOUTH LOUISIANA PROJECT PPPUD Drilling & Development Potential.OPERATED WORKING INTEREST SALT DOMENet Production: ~60 BOPDPP 5974DV

SOUTH LOUISIANA PROSPECT1-Proposed WellJEFFERSON DAVIS PARISH DVWOODLAWN FIELD6 Potentially Productive Zones At 9,700’Subsurface & 3D Seismic Defined GULF COAST75% Working Interest; 73% NRIEstimated Reserves: 929 MBODV 4491

ST. LANDRY PH., LA PROSPECT1-Proposed Well. 255-Acres. DVUPPER WILCOXTarget: Wilcox A Sand GULFTotal Depth: 12,500 Ft. NonPressured COASTSEEKING DRILLING PARTNEROffset Wilcox A Well Cum Prod: 52,775 BOEst Reserves: 510 MBODV 5747

VERMILION PH., LA MINERALS 12,190-Total Acres. (Fee/Royalty)LIVE OAK & ABBEVILLE MMULTI PAY EXPLORATION6,607+ Acres of Surface & Minerals GULF5,583+ Acres of Royalty Interest COASTMinerals & Surface Rights.APRIL 2017 SALE PACKAGEM 2166RR

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PetroScout 14 April 26, 2017

PERMIAN / WEST TEXASWEST TEXAS LEASEHOLD FOR SALE~10,230-Net Acres on Trend.LOVING & WINKLER COUNTIESPERMIAN - DELAWARE BASIN LProven Wolfcamp & Bone Spring BenchesPotential 400+ Horizontal Wells.All Depths Retained. WOLFCAMPLeases Will Deliver 75-87.5% NRIMostly Undeveloped Acreage.CONTACT AGENT FOR UPDATEL 2011DV

DAWSON CO., TX ACREAGE6-Vertical Wells. ~12,800-Net Acres.PERMIAN BASINHorizontal Targets: Lower Spraberry, LDean & Wolfcamp AIncludes Exisiting SWD System.Geological & Petrophysical Data Available100% OPERATED WI; 75% NRIExisting Production: 50 BOPD SPRABERRYOffset EURs: 1.2 MMBOE (L Sprayberry)Offset Operators: Tall City, Energen,RSP Permian & DiamondbackCONTACT AGENT FOR MORE INFOL 5964

NORTH MIDLAND BASIN PROSPECT~8,600-Net Acres w/Running Room.DAWSON COUNTY, TEXAS DV3D & Commingled Vertical Potential.Horizontal Upside & PDP Targets.Subsurface & 3D Data Available. SPRABERRY100% OPERATED WI; 75% NRIPotential Reserves: 200-400+ MBOE/WellDV 5244

NORTH TEXASCOOKE CO., TX PROSPECT1-Prospect.FRACTURED ELLENBURGER -- DV-- DOLOMITE PLAYTest Depth: 4,300 Feet. ELLENBURGERMMBO Reserve Potential.DV 4522

JACK CO., TX PROPERTY67-Total Wells. ~5,070-Net Acres.MARBLE FALLS & CADDO5 Productive Bryson Sands PPUp To 100% OPERATED WI; ~37-80% NRIGross Production: 42 BOPD & 379 MCFD6-Mn Avg Net Income: $23,713 Per Month ~105Area Operators: HEP Oil GP, Renaissance, BOEDJay Management & Aspen OperatingCONTACT AGENT FOR UPDATEPP 4297DV

SOUTHEAST TEXASWHARTON CO., TX PROSPECTProposed Shallow Gas Well.WEST BERNARD FIELDPROLIFIC PRODUCING AREA DVMiocene. ~3,200 Ft.3-D Seismic Data Available50% NonOperated WI For Sale SHALLOWNearby Reservoir Prod 6.3 BCF (3 Wells)Potential P50: 1.6 BCFGROUND FLOOR DRILLINGDV 8609

PERMIAN / WEST TEXASECTOR CO., TX ACREAGE 600-Net Acres. (100% HBP)WOLFCAMPSHALLOW RIGHTS LWolfcamp, Spraberry & Clear Fork RightsAccess To Multiple Horizon Targets WOLFCAMPUp to 100% OPERATED WI; 75% NRI PLS IS GATHERING BUYER LEADSL 9982DV

ANDREWS CO., TX LEASEHOLD430-Net Acres.PERMIAN BASINMultiple Sections - Including Sec 16, LBlk A-30, et al.NonProducing Leasehold w/ Potential in SANSan Andres, Clearfork, & Wichita Albany. ANDRES100% OPERATED WI FOR SALE2017, & 2018 Expirations.All Offers Are Being Considered.L 5889

CRANE & PECOS CO., TX MINERALS19,350-Net Mineral Acres.PERMIAN BASINS. Delaware Basin & Central Basin Platform MHZ Development Upside.Acreage Offset Apache’s Alpine High PlayLegacy HBP Position In Crane County ALPINE19.2% ROYALTY INTEREST AVAILABLE HIGHOperators Producing From Stacked Pay2016 Income: $208,333/MonthCONTACT AGENT FOR UPDATEM 2690

WEST TEXAS ASSETS FOR SALE~64,000-Net Acres. 2-Packages.MIDLAND & DELAWARE BASINSGlasscock, Howard & Culberson Cos. PPLower Spraberry, Bone Spring, Barnett,Woodford, Wolfcamp A, B & CDelaware Pkg Offset Apache’s Alpine High100% OPERATED WI AVAILABLE PERMIANMidland Net Production: ~1,100 BOEDDelaware Net Production: ~200 MCFEDSubstantial Existing Infrastructure.CONTACT AGENT FOR MORE INFOPP 9070PKG

SOUTHEAST TEXASSOUTHEAST TEXAS FARMOUT2-Wells. ~1,344-Gross HBP Acres.GRIMES & WALKER COUNTIESSHIRO AREA - EAGLEBINE / CHALK FOObj 1: Austin Chalk. 12,115 Ft.Obj 2: Eaglebine. 12,400 Ft.Farming Out All Rights For Lease Bonus---- And ORRI AUSTIN100% OPERATED WI AVAILABLE CHALKOperator Will Retain Existing Wellbores ---- & Will Maintain HBP Status.FO 2617DV

SOUTHEAST TEXAS MINERALS900-Net Mineral Acres.GRIMES & WALKER COUNTIESEaglebine, Buda & Glen Rose Primary Objs MGeorgetown, Kiamichi, Goodland/Edwards& Paluxy Additional ObjectivesMinerals Leased By EOG MINERALSMINERALS FOR SALECONTACT AGENT FOR MORE INFOM 4289

SOUTHEAST TEXAS NONOPERATED51-Active Wells. 15,722-Gross Acres.BRAZOS COUNTY EAGLEBINE & AUSTIN CHALKStable PDP Component. PPInventory Of Repeatable PUD Locations.Contiguous Acreage Is >98% HBP.10% NonOperated WI; 7.5% NRI ~125Net Production: 108 BOPD & 118 MCFD BOEDAvg Net Cash Flow: ~$119,000/MonthEst Net Proved Reserves: ~1.5 MMBOEEst Net Proved PV10: ~$13,280,000AGENT COLLECTING OFFERSPP 9980DV

TRINITY CO., TX PROPERTY2-Total Wells. 9,931-Net Leasehold Acres.GULF COAST BASIN1-Producing & 1-NonProducing Well. PPDeep Bossier Production With TravisPeak Behind Pipe PotentialLeasehold Can Deliver 84.41% NRI BOSSIER100% OPERATED WI; ~72-75% NRI6-Mn Avg Gross Production: 359 MCFD6-Mn Avg Net Income: $2,439 Per MonthAGENT WANTS OFFERS APR 26PP 5412DV

WHARTON CO., TX PROSPECT80-Acres.SOUTHEAST TEXASFrio Sands Primary Objective DVShallow Miocene Secondary ObjectiveTarget Depth: 5,950 FeetUp To 85% WI AVAILABLE; 75.8% NRI FRIOPotential Reserves: 140 MBO & 320 MMCFDHC: $350,000; Compl: $380,000DV 1573

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Volume 28, No. 06 15 e&POKLAHOMA

OKLAHOMA OIL PROJECT3-Producing Wells. 10,400-Acres HBP.WASHINGTON COUNTY (4-BLOCKS)SHALLOW GAS ZONES DVProven Upper Mississippi. ~1,750 Ft.8-Proposed Wells.OPERATIONS AVAILABLE MISSUp to 50% NonOperated WI; 80% NRI CHATCurrent Prod: 25 BOPD & 300 MCFDOffset Vert. Miss. Well IP: 104+ BOPDCumulative Production: 12,000 BODrill & Completion: ~$150,000 per WellDV 3155PP

OKLAHOMA UPSIDE PROSPECTS93-Rigs Running.MIDCONTINENT>4,300 Future Development Locations. DVSignificant Regulatory Activity.Area Operators: Continental, Newfield,Devon, Chesapeake, Cimarex & BP MIDCONUPSIDE DEVELOPEMT FOR SALEThis Is A Sub Package To A Larger Package.CONTACT AGENT FOR UPDATEDV 2825

SOUTHEAST OKLAHOMA PROPERTIES152-Total Wells. ~6,250-Net Acres.ARKOMA BASINHorizontal Woodford Production PP125 Gross HZ Woodford Locations.10 Rigs Currently Running.OPERATED & NonOperated WI Available ~20Net Production: 19 MMCFED MMCFEDExp 12-Mn PDP Cash Flow: $1,250,000/MnPDP Reserves: 87 BCFEPDP PV10: $76,000,000Extensive Pipeline & Processing In PlaceAGENT WANTS OFFERS MAY 17PP 4604

PANHANDLE TEXASMOORE CO., TX PROSPECT80-Potential Wells. 3,000-Acres.WOLFCAMP / DOLOMITE DV30 Prospects.Workover Depth At 3,800 Ft.OPERATIONS NEGOTIABLE MIDCON30-50% WORKING INTEREST; 75% NRIExpected IP Rate: 400 BOPDDHC: $25,000 - $40,000 Per WellDV 2235

OLDHAM CO., TX PROSPECT3-Potential Wells. 640-Acres. DVSOUTHERN DALHART BASINMissourian Carbonate At 6,350 Ft. NONOP3D Seismic, Subsurface & Geophysics55% NonOperated WI; 77% NRIExpected IP: 200 BOPD (Missourian)DV 2923

OKLAHOMACENTRAL OKLAHOMA ASSETS16,690-Net Contiguous Acres.SCOOP - MERGE FAIRWAYCanadian, Grady, McClain & Garvin Cos. PPWoodford Shale & Additional ExposureTo Lower MississippianAcreage Is ~60% Held By Production ~500OPERATED WI AVAILABLE BOEDNet Production: ~500 BOED54% Oil, 28% NGL & 18% GasAGENT WANTS OFFERS JUN 8PP 4164DV

CENTRAL OKLAHOMA SALE PACKAGE161-Total Wells. 4,862-Net Acres (HBP).SOHOT/HOXBAR - ANADARKO BASINHBP Leasehold, Mineral & Surface Fee PPOperated WI, NonOp WI, RI & ORRIGross Prod: 278 BOPD & 22,617 MCFD ORRI6-Mn Avg Net Income: $128,900/MonthAGENT WANTS OFFERS MAY 11, 2017PP 4161L

GARFIELD CO.,OK MINERALS315-Net Mineral Acres.NORTHWEST STACK MMINERALS FOR SALEHBP & Non-Producing Minerals STACKCash Flow: $3,300 Per MonthCONTACT SELLER FOR MORE INFOM 5107

GRANT CO., OK PROSPECT7,800-Gross Acres. 7,200-Net Acres. DVMIDCONTINENT MISSISSIPPIANPrimary Target: Mississippian FormationHBP Leasehold Opportunity.DV 5866

MCINTOSH CO., OK PRODUCTION320-Total Acres; 1-Producing WellARKOMA BASIN - TEXANNA FIELDOptional: 2nd Well On 640-Acres. PPBooch Sand. 55 Ft. ThickSelling Half Or All Of A 640 Acre Unit ARKOMAExisting Operator Can Remain (If Req’d)100% WI Operations AvailableGross Production: 22 MCFDPP 4514DV

OKLAHOMA NONOP & LEASEHOLD46-Operated Wells. 762-Net Acres.SCOOP PLAYWoodford Production & Springer Upside PPTarget Depths At 15,000 to 24,000 Ft.173 Possible Undeveloped Locations.Leasehold Can Deliver 80% NRI SCOOP2.85% NonOperated WI; 2.25% NRIMay 2017 Net Prod: 98 BOPD & 480 MCFDProj’d May 2017 Net Cash Flow: $191,475/MnAGENT WANTS OFFERS MAY 1PP 5668DV

NORTH TEXASJONES CO., TX PROSPECT6-10-Potential Wells. 160-Acres.EASTERN SHELFFrye/Tannehill Sand At 1,650 Ft. DVBluff Creek Sand At 1,900 Ft.Great Shallow MultiPay AreaDefined By Subsurface Geology TANNEHILL100% OPERATED WI; 77% NRIExpected IP Rates: 20-100 BOPDOffsetting Proven Production By Good OilEst Net Reserves: 10-40 MBO Per WellDHC: $100,000; Compl: $110,000DV 2474

NORTH TEXAS ASSETS FOR SALE17-SWD Wells. ~80,000-Net Acres.JACK, PALO PINTO & CLAY COUNTIESFORT WORTH BASINTargets: Marble Falls, Barnett, Strawn, PPConglomerate & Caddo Formations.224-Behind Pipe Opportunities.398-PUD & 232-Probable Drilling Locations~100% OPERATED WI; ~75% NRIDec 2016 Net Sales: ~2,600 BOED ~2,600Total 2P Reserves: 82,160 MBOE BOEDTotal 2P PV10: $357,000,000400+ Miles Of Gas/Water Flow Lines &Pipeline In PlaceCONTACT AGENT FOR UPDATEPP 2550DV

OKLAHOMAALFALFA CO., OK MINERALS~168-Net Mineral Acres (HBP). MNORTHWEST STACK EXTENSIONMINERALS FOR SALE MINERALSCurrent Cash Flow: $17,280 Per MonthCONTACT SELLER FOR MORE INFOM 5308

ALFALFA CO., OK MINERALS30-Net Mineral Acres.NORTHERN OKLAHOMA MMINERALS FOR SALENonProducing Minerals. MINERALSCONTACT SELLER FOR MORE INFOM 2535

CENTRAL OKLAHOMA ASSETS59,746-Net Acres. 127-Sections. 4-SWD.ANADARKO BASIN - STACKGarfield & Kingfisher Counties PPOsage, Meramec & Oswego FormationsPosition Is ~85% Held By ProductionTitle Opinions Covering 100% Of Acreage74% OPERATED WI AVAILABLE ~2,200Current Net Production: ~2,200 BOED BOEDPV10: >$50,000,000100% Owned Infrastructure Across PositionAGENT WANTS OFFERS MAY 3PP 2000DV

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PetroScout 16 April 26, 2017

COLORADOCOLORADO FARMIN OPPORTUNITY2-Units. >33,000 Gross Acres.RIO BLANCO & MOFFATT COUNTIESPICEANCE BASIN DVUnitized on Niobrara Formation.13,100 Ft. Vertical to Frontier Formation~22-100% OPERATED WI AVAILABLE NIOBRARA2014 HZ Niobrara Well Flowed 891 BOPD 21 Month Cum of 147 MBOE (69% Oil)Offset Prospect Rsrvs: 200-500 MMBOEDV 2935FO

COLORADO PROSPECTS42,000-Gross & Net Acres.MORGAN & WASHINGTON COUNTY DVDJ BASINObj 1: Cherokee. 6,000 Ft.Obj 2: Marmaton. 6,500 Ft. DJ BASINAdditional Upside in Atoka.Subsurface Geology Data100% OPERATED WI; ~78% NRIDV 3908L

DJ BASIN NONOP ASSET SALE~3,800-Net Acres. 7-Producing Wells.ADAMS & WELD CO., COSouth Wattenberg Brighton Area PPCodell & Niobrara A, B & C5 Wells Being Completed & Online Q2 2017450+ Gross Potential Locations.NONOPERATED WI AVAILABLENet Production: 940 BOED (70% Oil) 940 BOEDOperators: Great Western, PDC Energy,Petro Operating & Ward PetroleumAGENT WANTS OFFERS EARLY MAYPP 2351DV

MONTANAVALLEY CO., MT ASSETS41-Wells. 4-SWD. 11,532-Net Acres.CONVENTIONAL OILCharles C & Nisku Formations PPAcreage Is 76% Held By Production31 Total Shallow 3P Locations IdentifiedAdditional WI In Acreage Pooling Agreement100% OPERATED WI AVAILABLEEst Feb 2017 Net Prod: 160 BOPD CONVENTIONALEstimated 3P Reserves: 2.9 MMBO Estimated 3P PV9: $26,400,000Pipeline Transport.CONTACT AGENT FOR UPDATEPP 2100DV

MULTISTATE ROCKIESWILLISTON BASIN MINERAL LEASE~6,000,000-Mineral Acres. MMONTANA, NORTH & SOUTH DAKOTAMINERALS FOR LEASE ROCKIESM 2680

PENNSYLVANIAMCKEAN CO., PA MINERALS+/-303-Net Mineral Acres.ANNIN & CERES TOWNSHIP MAPPALACHIAN BASINUnleased Acreage. MINERALSMINERALS FOR SALEM 5316

PENNSYLVANIA BANKRUPTCY+/-5,602-Net Mineral Acres. DVCAMBRIA & CLEARFIELD COUNTIES+/-1,750-Acres Held By Production. BANKRUPTCYOperators: Dorso & S&D EnergyCONTACT SELLER FOR MORE INFODV 1905AU

POTTER CO., PA MINERALS+/-165-Net Mineral Acres. MGENESEE & OSWAYO TOWNSHIPSAPPALACHIAN BASIN MINERALSMINERALS FOR SALE OR LEASEM 2794

WEST VIRGINIABROOKE CO., WV MINERALS+/-204-Gross & Net Mineral Acres. MCROSS CREEK DISTRICTAPPALACHIAN BASIN MINERALSMINERALS FOR SALEM 4671

MARCELLUS ACREAGE <5,000-Acres.WEST VIRGINIA & OHIO LOPERATED & NonOperated Positions.L 5216DV MARCELLUS

MARSHALL CO., WV MINERALS+/-20-Net Mineral Acres. MMEADE DISTRICTAPPALACHIA BASIN MINERALS18% NET ROYALTY RATE5-Yr Primary Term & 3-Yr Extension Term.M 2200

MONONGALIA CO., WV MINERALS+/-152-NMA. +/-117-NRA.BATTELLE DISTRICT MAPPALACHIA BASINLessee: EQT Production Company ROYALTY16% Net Royalty Rate5-Yr Primary & 5-Yr Extension Terms.M 4364

WETZEL CO., WV MINERALS+/-42-Net Mineral Acres. MCHURCH DISTRICTAPPALACHIAN BASIN MINERALSMINERALS FOR SALEM 4485

PANHANDLE TEXASROBERTS CO., TX SALE PACKAGE8-Producing Wells. 540-Net Leasehold Acs.GRANITE WASH - ANADARKO BASINBehind Pipe Potential In Lower Douglas PP100% OPERATED WI; 75% NRIGross Prod: 86 BOPD & 1,179 MCFD UPSIDE6-Mn Avg Net Income: $145,552/MonthAGENT WANTS OFFERS MAY 3PP 4373L

OHIOMONROE CO., OH MINERALS+/-33.55-Net Mineral Acres.WASHINGTON TOWNSHIP MAPPALACHIA BASINAcreage Is Held By Production.Lessee: Gulfport MINERALS12.5% ROYALTY RATEM 5127

OHIO ACREAGE FOR SALE 2-Tracts. 500-Acres.UTICA & MARCELLUS POTENTIAL DVOperated & NonOperated PositionPACKAGE READY MAY 1 UTICADV 9057L

SOUTHERN OHIO PROJECT>13,400-Gross Acres. (Contiguous)JACKSON, GALLIA & VINTON CO.Utica Shale / Point Pleasant Potential LShallower Lower Huron Shale OpportunityIncludes 4 Shallower Horizontal Wells100% OPERATED WI; 87.5% NRI UTICASEEKING OUTRIGHT SELL OR JV SHALEGathering & Operator Owned Pipeline.Pipeline Included. Tapped Into One & --Access to Two Major Interstate Pipelines.5-Year Initial Lease Term w/ RenewalsL 9828DV

PENNSYLVANIABEAVER CO., PA MINERALS+/-26-Net Mineral Acres. MINDUSTRY BOROAPPALACHIA BASIN MINERALSMINERALS FOR SALEM 4135

GREENE CO., PA MINERALS+/-54-Net Mineral Acres.MONONGAHELA TOWNSHIP MAPPALACHIA BASINAcreage Is Held By Production. MINERALS12.5% ROYALTY RATEM 2391

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Volume 28, No. 06 17 e&P

Chisholm Oil & Gas starts up in STACK playTulsa-based Chisholm Oil & Gas is a new Oklahoma-focused E&P company that

has picked up an initial 53,000 acres in the multi-zone STACK play in and around Kingfisher County. Backed by a $900 million commitment from Apollo Global Management to develop the acreage, Chisholm is led by CEO Bob Zinke.

The Chisholm team has a deep background hailing from Bakken first mover Zenergy, which Zinke co-founded with Dave Trumbo in 1980 as Zinke & Trumbo. That company drilled more than 200 horizontal wells on both sides of North Dakota’s Nesson Anticline. That team also was among the first to apply horizontal drilling techniques in the Mission Canyon, Poe and East Fork fields.

“We are excited to be working with Apollo’s managed funds to build a premier STACK-focused independent E&P business,” Zinke said. “We believe the STACK has some of the best geology of any shale play in the US, and Chisholm has tremendous growth potential given the multiple oil-weighted target formations, repeatable results and high single-well economics.”

Gulfport’s first completions in SCOOP coming soon

Gulfport has begun its first operated completions in the SCOOP following the closing of its Vitruvian buy. The company

is using an enhanced frac design compared with historical completions,

and results are expected in the coming weeks. The design utilizes 2,250-2,400 lb of proppant per foot with 180-ft stage lengths. Gulfport didn’t disclose details of Vitruvian’s design. Four operated rigs are running in the play.

The company also reported that net Q1 volumes averaged 849.6 MMcfe/d, up 8% sequentially largely on the strength of the Utica. Gulfport commissioned field-level compression in the play that resulted in 45% initial uplift to volumes, which CEO Michael Moore said was above expectations. During Q1, Gulfport produced an average ~751 MMcfe/d.

Midcontinent Unit enhances Hoxbar with acreage, waterflood opportunity Unit Corp. augmented its Hoxbar position in Grady and Caddo counties,

Oklahoma, with an acquisition that added horizontal drilling locations and waterflood potential to the asset. The acreage complements Unit’s current operations. Of the 65 horizontal drilling locations, 13 are new and Unit’s working interest in the remaining

locations will increase. Proved reserves are 3.2 MMboe. Additionally, the acquisition offers waterflood upside. It gives Unit operational

control of key areas of the Marchand zone of the Hoxbar reservoir for secondary-recovery efforts. At least initially, Unit said, “It is anticipated that the initial secondary-recovery phase will increase the reserve potential from the Marchand interval by at least 500,000 boe per well.” Currently, Unit’s Marchand wells have average EURs of over 500,000 boe.

“We plan to pick up a rig in the second quarter to continue developing the area,” said CEO Larry Pinkston.

“Coupled with the waterflood potential, we believe the value of this core holding will be significantly enhanced.” Unit plans to drill seven wells in the play this year.

Alta Mesa eyes eight rigs in STACK this year

Alta Mesa Holdings will drill and complete up to 150 wells this year, ramping up from six to eight rigs by year’s

end. The company increased its capex 28% this year to $290 million with 95% of that going

to Kingfisher County, Oklahoma. Joint development partner Bayou City Energy will fund 42 of the wells.

Alta Mesa increased its STACK position from 40,000 net acres in early 2015 to over 100,000 net acres today. The company aims to delineate the Osage, Meramec and Oswego formations and it will drill at least one Manning well. It has also begun infill development in the Osage and Meramec. Alta Mesa’s latest-generation completion design utilizes 150-ft stage spacing (32 stages), up from over 250 ft (12 stages) in the first generation.

WildHorse Resource Development will bring 100 wells online Newly public WildHorse Resource Development plans to spend $450-600 million on

D&C in 2017 to bring 80-100 wells online. The company is running five rigs in the Southeastern Eagle Ford and one in North Louisiana after ramping up from one rig toward the end of 2016. Most of the company’s rigs are in Burleson County, Texas, which is the most active county in

the Southeastern region. Well results and returns in

Burleson County have shown significant improvement. Gen 3 slickwater completions (16 wells) have yielded 28% improvement in EUR per 1,000 lateral feet since Gen 1 (seven wells) despite laterals remaining around 6,200 ft. These wells are tracking with an EUR of 97,000 boe per 1,000 ft (594,000 boe total)—above WildHorse’s Burleson core type curve of 91,000 boe per 1,000 ft. In addition to better recovery, D&C costs have fallen 67% since Gen 1. For reference, Gen 1 wells were hybrid completions that are tracking with 76,000 boe per 1,000 ft (430,000 boe total).

CEO Jay Graham said WildHorse would delineate its acreage position, test new completion designs and explore new targets.

Plan calls to drill and complete 150 wells in Kingfisher County.

Added compression boosts Utica volumes 45%.

Regional Oil & Gas Intelligence November 18, 2015

Serving the local market with drilling activity, permits & deals for sale Volume 03, No. 22

OKLAHOMA & KANSAS ~11,000-Net Acres. (100% HBP)WOODS CO., OK & BARBER CO., KS21 Active Wells. 3 Horizontal. PPOPERATED & NONOP WI FOR SALEGross Prod:69 BOPD & 2.2 MMCFDTotal Proved: 111 MBO, 4.6 BCF, & -- 2.3--& 160 MBC NGL MMCFEDSELLER IS REVIEWING OFFERSPP 5989DV

NORTH TEXAS PROSPECTS2-Prospects. Up to 500 Acres.FT. WORTH BASIN AREA DVProven Shallow Oil PotentialOil Pay Objectives At 1,000’ - 5,000’Generator Will Participate Up To 25% WINearby Field Cum’s : 80 MBO-18 MMBODV 5259

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MIDCONTINENT SCOUT

Continental STACK Position

EXCELLENT POSITION IN PLAY • ~146,300 NET ACRES• ~95% IN OVER-PRESSURED WINDOW

-

• ~90% LIQUIDS-RICH• ~60% HBP

OUTSTANDING MERAMEC RESULTS

• 2,782 BOEPD, 2,100 PSI FCP (LUDWIG)

• 2,181 BOEPD, 2,000 PSI FCP(LADD)

• 994 BOEPD, 625 PSI FCP (MARKS)

• 73% TO 79% OIL

3 WELLS DRILLING AND 1 WELL WOC

CURRENT PLANS THROUGHYEAR END

• 2-3 OPERATED DRILLING RIGS • 2-3 ADDITIONAL WELLS TO SPUD

Normally-Pressured

Over-Pressured

Ladd 1-8-5XH Marks 1-9-4XH

Ludwig 1-22-15XH

CLR Leasehold

CLR Drilling Rigs

Industry Drilling Rigs

Industry Normally-pressured 2 mi. lateral

CLR Hz Meramec Wells

CLR Planned Wells 2015

Industry Over-pressured 2 mi. lateral

Industry Over-pressured 1 mi. lateral Industry Normally-pressured 1 mi. lateral

Source: Continental Resources November 04, 2015 via PLS docFinder (www.plsx.com/finder)

Regional Activity (State Data)(11/02/15 to 11/13/15)

Compls PermitsNebraska – 1Kansas 28 75Oklahoma 6 64North Texas (RRC 5) – 1North Texas (RRC 7B) 5 28North Texas (RRC 9) 13 30TX Panhandle (RRC 10) 4 8

Most Active Operators by Permits➊ Altavista Energy 16➋ Owens Petroleum 8➌ Enervest Operating 6

Permits by Formation (by Last Scout)

Formation 11/18 11/04 10/21

Squirrel 31 46 38Mississippian 21 23 34Arbuckle 8 15 15Bartlesville 8 17 6Barnett 7 5 3Woodford 7 14 5Cleveland 3 4 6Granite Wash 3 6 2Marble Falls 3 4 4Other Formations 116 147 104TOTAL 207 281 217Sources: TXRRC, OCC, KGS & NOGCCActive Rigs Running (Baker Hughes) 114

Chesapeake’s Oklahoma long laterals include record 9,395 ftDuring Q3, Chesapeake Energy drilled

a company record lateral length of 9,395 ft on its JJJ 23-25-11 1H well, which was in the completion stages as of the release of the company’s quarterly operations update.

That quarter also saw the first multi-lateral well drilled by Chesapeake in the Mississippian Lime, the Wilber 26-27-11 1H, which has dual laterals of 4,653 ft and 4,556 ft and is also being presently

completed. The company’s multi-section extended laterals that it is drilling in the Mississippian Lime save ~$1.4 million per well, a 27% decrease in D&C costs compared to two separate standard laterals.

Net production from the Mississippian Lime stayed relatively flat at an average of 31,000 boe/d during Q3, a 1% sequential decrease. Chesapeake says its YTD completed wells average laterals of 4,500 ft and nine frac stages at a cost of $2.8 million vs. its 2014 averages of 4,450 ft and nine frac stages at $3 million.

Continental bullish on STACK, SCOOP performanceThe stars of Continental Resources’

Q3 production were the company’s STACK and SCOOP wells, according to its most recent operational update. Continental completed its second and third STACK wells during the quarter and is drilling or completing four more. The company says its acreage in the trend will “compete head-to-head” with its SCOOP development, which the company says continues to show strong results.

Continental’s wells completed in the over-pressured STACK have 90-day rates

that are three times higher than wells in normally pressured windows. The Ludwig 1-22-15XH had a rate of 2,782 boe/d (76% oil), while the Ladd 1-8-5XH came

in at 2,181 boe/d (79% oil). Continental says 95% of its STACK acreage is in the over-pressured window. Through YE15, the company will operate 2-3 rigs and spud an additional 2-3 wells there.

Over-pressured STACK has 3x higher rates than normal-pressure window.

Multi-lateral wells & multi-section extended laterals drilled in Miss. Lime.

Continues On Pg 5

Continues On Pg 5

158 Completions; 173 Permits; 141 Rigs Running.

Midcontinent Scout April 19

Regional Oil & Gas Intelligence October 30, 2015

Serving the local market with drilling activity, permits & deals for sale Volume 78, No. 14

EAGLE FORD EAST PROPERTY3-Active. 11,262-Net Acres 76% HBP AGUILA VADO, GIDDINGS &--SOUTHERN BAY FIELDS PPBrazos, Burleson, Lee, Bastrop &--Fayette Cos., TXMostly Op WI; Varying NRI EAGLEGross Prod: 210 BOPD & 105 MCFD FORD40 Hz Locations Exist - More If JV (660’)PP 5320DV

FAYETTE CO., TX PROSPECT15+ Potential Wells. 2,500-Acres.UPPER TEXAS GULF COASTGLEN ROSE TREND DVGlen Rose ‘’D’’ Zone. 12,500 Ft.100% OPERATED WI; 75% NRI GLENExpected IP: 250 BOPD & 435 MCFD ROSEWell Reserves: 250 MBO & 625 MMCFDV 2441

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SOUTHEASTERN SCOUT

GOM Top Operators -Number of Permits (YTD 2015)

64

77

89

73

0

10

20

30

40

50

60

70

80

90

100

Anadarko ArenaO�shore

BHP BP Chevron Shell

17

85

• BHP’s SB-201 at Shenzi was the first well to come online after 2010 GOM moratorium.

• Chevron leads development of the GOM’s Lower Tertiary Wilcox trend.

Perm

its

BHP Billiton

Chevron

Gulf Of MexicoPermits

Source: PLS Research

Regional Activity (State Data)(10/01/15 to 10/27/15)

Compls PermitsAlabama – 5

Mississippi – 23

South Louisiana – 6

Southeast TX (RRC 3) 12 34

Gulf of Mexico – 29

Most Active Operators by Permits

➊ BP E&P 6

➋ Chevron 6

➌ Oak Grove Resources 5

Permits by Formation (by Last Scout)

Formation 10/30 10/09 09/17Eagle Ford 6 12 10Pottsville 6 – 1Wilcox 6 7 7L Cretaceous 3 – –Tuscaloosa 3 17 22Yegua 3 2 2Austin Chalk 2 – 2Cotton Valley 2 1 4Buda 1 3 7Other Formations 65 74 80TOTAL 97 116 135Sources: AOGB, BOEM, MSOGB, SONRIS & TXRRC

Active Rigs Running (Baker Hughes) 74

BHP continues Shenzi drilling after hitting hydrocarbonsNearly five months after the first of

two offshore sidetracks—the Shenzi North-ST1—came up dry, BHP Billiton reported it has encountered hydrocarbons with the second. The company is drilling ahead with the more promising Shenzi North-ST2 in Green Canyon Block 609 in the Gulf of Mexico 122 miles south of New Orleans.

BHP began sidetracking an exploration well in June at Shenzi, its flagship project in the deepwater Gulf, kicking off the first sidetrack at 22,500 ft. The company

spudded the second one, which kicked off at 13,340 ft, in mid-August.

The field’s total 3Q15 production was was 3.28 MMboe according to BHP’s Q3 operational update. Four months

into development, the field reached peak production of 149,500 bo/d. In May, the company reported production of 95,000 bo/d and facility utilization of 80%.

Sidetrack kicked off at 13,340 ft; dry hole at 22,500 ft.

Continues On Pg 3

Chevron finds 1,800-ft hydrocarbon column at AnchorThe deepwater Anchor oil discovery in

the Lower Tertiary Wilcox trend may be capable of supporting a hub development, according to Chevron. An initial appraisal well found 694 ft of net oil pay. The results confirm a Wilcox hydrocarbon column of at least 1,800 ft reservoirs at Anchor (55% WI) and indicate that the reservoirs are well developed. Additional delineation wells and technical studies are planned to fully appraise the Gulf of Mexico discovery.

Chevron has used hubs to develop other large GOM fields including the nearby Jack/St. Malo project, which is also in the Lower Tertiary Wilcox trend.

The supermajor holds 55% WI in Anchor with partners Cobalt International Energy (20%), Samson Energy (12.5%) and Venari Resources (12.5%).

Partner says Anchor could be one of largest Lower Tertiary Wilcox finds yet.

Continues On Pg 3

39 Completions; 81 Permits; 45 Rigs Running.

Southeastern Scout April 20

Zenergy alumni teams with Apollo to work in Kingfisher County.

Southeastern

86% of its E. Eagle Ford drilling locations are in Burleson County.

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PetroScout 18 April 26, 2017

Bakken output surpasses 1.0 MMbo/d in sign of uptick

North Dakota production climbed 5% from January to February to top 1.0 MMbo/d, returning to levels last seen in November prior to a 90,000 bo/d drop at the end of 2016.

Industry players have been projecting an uptick in drilling, and the hope is a Bakken revival is on the horizon as market access has opened up with startup of Dakota Access pipeline

and crude differentials have tightened. The region’s all-time production high was 1.23 MMbo/d in December 2014. The EIA projects Bakken volumes to stay above the 1.0 MMbo/d mark through May. Rig count is 44 in the Williston Basin, up from 33 to start the year.

The NDIC Department of Mineral Resources reported that 93 drilling permits were issued in March, the highest number in a single month this

year after tallies of 45 drilling permits in February and 81 drilling permits in January. The high was set in October 2012 at 370 permits issued. Producers were fetching $41.75/bbl as of April 13, up from $38.13/bbl in March.

NDIC director Lynn Helms said, “Operators are shifting from running the minimum number of rigs to incremental increases throughout 2017, as long as WTI oil price remains between $50/bbl and $60/bbl.”

However, Helms added, oil price weakness is expected through Q2. That, plus Permian competition for capital continue to keep down rig counts.

Bakken

The most impactful recent result was Chesapeake’s first completion in the Turner sand, which flowed 2,325 boe/d (78% oil) from a 7,100-ft lateral in mid-March. Chesapeake’s acreage is farther south than where EOG and Devon have been developing the Turner, so this completion results in a meaningful extension of the play. Based on initial results, Chesapeake says it has confirmed high rock quality and pressure on its acreage. It estimates more than 300 Turner locations primarily in southern Converse County on 2,640-ft spacing with EURs of 1.35 MMboe, single-well RORs of ~75% at

flat $60/bbl oil and $3.00/MMbtu gas, and a low breakeven oil price of ~$35/bbl.

Chesapeake’s Turner well followed a Niobrara test with an enhanced completion design in Converse County that yielded an IP rate of 1,650 boe/d (70% oil) in February. The company is running two rigs and one frac crew in the Powder River with flexibility to accelerate. In mid-April it reported a second Turner completion and its first Parkman completion underway along with initial Mowry drilling. Results are expected from the Parkman in May and the Mowry in late Q2 or early Q3.

Devon returned to the Powder River after a year-long hiatus, and its one-rig program is slated to drill 20 wells this year. In February, Devon completed three Parkman horizontals in Campbell County with IP rates ranging 813-1,584 boe/d (96-97% oil) and two Teapot horizontals with rates of 735 boe/d (96% oil) and 1,196 boe/d (94% oil), according to state records reviewed by PLS. Devon drilled laterals ranging from less than 7,500 ft to more than 9,200 ft in the Parkman and ~3,850 ft in the Teapot. Thanks to high-oil cuts and stabilizing WTI prices, Devon recently raised its high-return inventory estimate by 20% to 240 locations: 40 Teapot, 75 Parkman and 125 Turner.

After focusing on the Turner for most of 2016, EOG resumed Parkman drilling in Q4 and applied its latest D&C techniques to achieve three wells with 30-day rates averaging 2,200 boe/d. Early results this year also include a Niobrara test flowing 509 boe/d (82% oil). With an expanded inventory from its acquisition of Yates Petroleum, EOG has increased its Powder River drilling plan 50% YOY to 30 wells.

Western

Regional Oil & Gas Intelligence November 3, 2015

Serving the local market with drilling activity, permits & deals for sale Volume 02, No. 14

MUSSELSHELL CO., MT ACREAGE77,413-Gross & 52,200-Net Acres.CENTRAL MONTANA UPLIFT LMISSISSIPPIAN HEATH OIL PLAYProposed Depths: 3,600-9,675 Ft. HEATH100% OPERATED WI FOR SALE SHALEOffset Production: ~100 BOPDL 3185DV

SHERIDAN CO., MT PROSPECTS10-Potential Wells. 3-Prospects.WILLISTON BASIN DVMULTIPAY PROSPECTSRed River. 11,300 Ft.Mission Canyon & Others. 7,500 Ft.60% OPERATED WI; 48% NRI MULTIPAYExpected IP (Red River): 375 BOPDWell Reserve: 300 MBOE/Well DV 3851

Deals For Sale

No Commission. Call 713-650-1212

All Standard Disclaimers & Rights Apply.

BAKKEN SCOUT

Regional Activity (State Data)(10/08/15 to 10/29/15)

Compls Permits

North Dakota 25 136

South Dakota – –

Montana – 2

Most Active Operators by Permits

➊ EOG Resources 32

➋ Continental Resources 21

➌ QEP Energy 12

Permits by Formation (by Last Scout)

Formation 11/03 10/13 09/22

M Bakken 12 16 9Three Forks B2 10 3 1Three Forks B1 7 9 13Bakken 3 7 7Three Forks B3 2 2 1Cut Bank 1 – –Duperow 1 – –Three Forks B4 1 – –Other Formations 101 78 111TOTAL 138 115 142Sources: MBOGC, NDIC & SDDNR

Active Rigs Running (Baker Hughes) 63

Statoil long lateral flows at 3,486 boe/d from the BakkenInternational player Statoil flowed a

long-lateral Bakken well at 3,071 bo/d and 2,489 Mcf/d (3,486 boe/d, 88% oil). The Heen 26-35 #7H was drilled with a 9,604 ft lateral in Todd field in Williams County, North Dakota.

Two other Statoil completions in Williams County, the Smith Farm 23-14 #6TFH and #7H, are also long laterals drilled in Cow Creek field. The #6TFH targets the Three Forks with a 10,560-ft lateral and

flowed at 2,369 bo/d and 2,735 Mcf/d (2,825 boe/d, 84% oil) and the #7H has a 10,313-ft lateral targeting the Bakken, flowing 2,285 bo/d and 2,508 Mcf/d (2,703 boe/d, 85% oil).

Statoil’s Bakken assets include 330,000 net acres with an extensive gathering system for transportation and resource marketing.

Has 330,000 net acres in the play along with gathering system.

Continues On Pg 3

Top 20 Statoil Williston Basin Completions (01/15/15 - 09/25/15)

County Operator Well Name Field Reservoir TD boe/d Oil %McKenzie Statoil Johnston 7-6 #4H Banks Bakken 22,420 5,129 75%Mountrail Statoil Bures 20-29 #5H Alger Bakken 20,610 4,354 85%Mountrail Statoil Bures 20-29 #6TFH Alger Three Forks 20,646 4,047 86%Williams Statoil Judy 22-15 #5H East Fork Three Forks 20,720 3,894 86%Williams Statoil Hawkeye 16-21 #3H Todd Bakken 21,281 3,884 89%McKenzie Statoil Maston 34-27 #5TFH Banks Three Forks 20,775 3,791 76%Mountrail Statoil Bures 20-29 #3H Alger Bakken 20,254 3,759 86%Williams Statoil East Fork 32-29 XE #1H East Fork Bakken 19,985 3,726 87%Williams Statoil Folvag 5-8 XE #1H Stony Creek Bakken 20,765 3,686 87%Williams Statoil Heen 26-35 #7H Todd Bakken 20,310 3,486 88%Williams Statoil Irgens 27-34 #5H East Fork Bakken 20,350 3,399 82%Williams Statoil Irgens 27-34 #3H East Fork Three Forks 10,830 3,295 83%Williams Statoil Judy 22-15 #3H East Fork Three Forks 20,990 3,260 85%McKenzie Statoil Maston 34-27 #6H Banks Bakken 21,415 3,143 71%Williams Statoil East Fork 32-29 #6TFH East Fork Three Forks 10,699 3,065 87%Williams Statoil Field Trust 7-6 #4H Todd Bakken 20,442 2,893 90%Williams Statoil Smith Farm 23-14 #6TFH Cow Creek Three Forks 21,235 2,825 84%Williams Statoil Folvag 5-8 #6TFH Stony Creek Three Forks 20,824 2,774 88%Williams Statoil Smith Farm 23-14 #7H Cow Creek Bakken 20,925 2,703 85%Williams Statoil Folvag 5-8 #5H Stony Creek Bakken 20,820 2,656 87%Source: North Dakota Industrial Commission

SM reports efficiency gains despite delaying completionsIn the Bakken/Three Forks, SM

Energy production increased 27% YOY in Q3 but dropped 7% sequentially to 22,200 boe/d (85% oil) as the company increased its completion backlog to 47 wells. The company reported that it has

reduced drilling times to 15-21 days—down by 11% vs. 2014—and has drilled several Divide County wells in fewer than 10 days. Overall costs are down 20-25% vs. 2014. Furthermore, enhanced completions including plug-and-perf

with cemented liners are driving 20-30% increases in recoveries per well.

SM has been adding Bakken resources to its Three Forks inventory, and nine

Middle Bakken wells are performing above its Three Forks type curve. Two

additional recently completed wells could extend SM’s Divide County Bakken footprint farther south.

The company also recently announced the opening of a new office in Williston, North Dakota that SM calls a “tangible indication” of its commitment to growing its North Dakota operations.

Drilling times down by 11% & costs down 20-25% vs. 2014.

19 Completions; 144 Permits; 44 Rigs Running.

Bakken Scout April 25

NDIC: Incremental rig gains expected throughout the year.

Bakken volumes recover from a 90,000 bo drop at end of 2016.

New round of Powder River drilling Continued From Pg 1

Chesapeake’s first Turner well opens new area south of Devon/EOG activity.

Powder River Horizontal Completions Reported YTDCompletion Date Operator Reservoir County Lateral

(ft)IP Rate (boe/d) % Oil

02/25/17 Devon Parkman Campbell 9,233 813 97%02/23/17 Devon Parkman Campbell 8,223 1,166 96%02/20/17 EOG Turner Campbell 3,870 777 92%02/16/17 Devon Parkman Campbell 7,461 1,584 97%02/16/17 Chesapeake Niobrara Converse 6,460 675 49%02/15/17 Devon Teapot Converse 3,839 735 96%02/14/17 Devon Teapot Converse 3,850 1,196 94%02/12/17 EOG Niobrara Campbell 8,705 1,618 81%02/11/17 Ballard Parkman Campbell 4,025 3,323 89%02/03/17 Chesapeake Niobrara Converse 8,553 908 55%02/02/17 Chesapeake Niobrara Converse 9,466 1,638 65%01/27/17 Aethon Ft. Union Natrona 4,483 338 9%01/09/17 EOG Niobrara Converse 4,073 509 82%01/03/17 EOG Parkman Campbell 3,796 1,961 95%

Source: PLS Research using state data.

For general inquiries, email info@plsx.com

Volume 28, No. 06 19 e&P

Access PLS’ archive for previous E&P news

California Resources inks another San Joaquin Basin JV California Resources Corp. has formed its second JV of the year, this time

with Macquarie Infrastructure and Real Assets (MIRA). Under the JV, MIRA will commit an initial $160 million over two years to develop CRC’s Kern Front, Mt. Poso, Pleito Ranch and Wheeler Ridge fields in the San Joaquin Basin. MIRA may increase

investment up to $300 million. MIRA is funding 100% of the well costs to earn 90% WI. Once

MIRA achieves an agreed-upon return, CRC’s working interest will increase to 75%. The JV follows one announced last month with Benefit Street Partners for up to $250 million.

Last month, CRC CEO Todd Stevens said his company was at an inflection point with activity levels and would move from defense to offense. The company set a $300 million budget, increasing capital investment for the first time since spinning off from Oxy in 2014. Of the MIRA deal, Stevens said, “We are pleased to partner with MIRA to bring forward the value of our large and long-lived inventory and help to derisk and accelerate the development of CRC’s vast resource base.”

Massif’s Turner pair flow ~1,000 boe/d each The Powder River Basin is among the hottest plays in 2017. Privately-held Massif

Oil & Gas is among the companies driving increased activity. CFO Scott Sheehan reports that his company has flowed two strong Turner horizontal wells in the northeast extension of the core, kicked off a five-well spring campaign and will run a rig through summer.

Completed in Q4, the Chimney Cone 34-34 TH had a peak 30-day IP of 992 boe/d (89% liquids). Cumulative production over the first 90 days totaled 74,000 boe (822 boe/d). The well’s lateral was 4,032 ft, and

it was completed with 1,558 lb per foot of proppant. The second well sports a slightly longer lateral at 4,171 ft, and it was completed in February with 1,518 lb of proppant per foot. The well’s peak IP-30 was 1,034 boe/d.

Massif began a five-well drilling program in March to continue Turner delineation and test the Parkman formation in the northeast extension, Sheehan said. The first well of the program, Chimney Cone 22-41 TH, set a drilling record of 11 days from spud to rig release—which improved upon the first two horizontals by 25%.

Massif operates in Hilight field as MCL 1 Oil & Gas, backed by a private investment company. Massif acquired this field in 2015, and it historically produced from the Muddy sandstone.

“The San Juan Basin acquisition fits the profile of the established, conventional assets Hilcorp typically aims to secure and enhance,” said Jason Rebrook, president and chief development officer. “In the last five years alone, we have invested heavily

in our properties, increasing both reserves and production.” Hilcorp said its formula is to “grow the company by acquiring and

developing conventional oil and gas assets, then leveraging its core competencies and operational expertise to optimize their performance.” Most recently, Hilcorp has acquired conventional assets in South Texas and Wyoming, it said, and was looking to enhance its southwestern US presence. “When we make a decision to expand, we spend capital to increase production, improve infrastructure and extend the economic life of the asset,” said president and COO Greg Lalicker.

The San Juan assets produced 744 MMcfe/d (~80% gas; 20% NGLs; 2% oil) during 2016, and they’re expected to yield 690 MMcfe/d in 2017. Hilcorp didn’t offer details into specific plans for the assets. Subsidiary Hilcorp San Juan will operate the assets.

Western ■ Bonanza Creek’s reorganization

plan has been confirmed three months after filing for Chapter 11 protection. The Rockies producer expects to emerge from bankruptcy by the end of April.

■ Camber Energy said J. Fred Hofheinz has resigned from its board. The company has no immediate plan to fill the seat.

■ Permian-focused Centennial Resource Development hired Brent Jensen as VP and chief accounting

officer to replace Jamie Wheat, who resigned

effective March 24 but will remain with the company as accounting VP during the transition. Jensen previously served as finance VP and treasurer of Whiting Petroleum after more than 10 years in PricewaterhouseCoopers’ oil and gas audit practice.

■ Development Capital Resources (DCR) has started up with backing from Ares Management funds. DCR will seek to partner with existing operators across the country and has already launched two partnerships. Houston-based DCR is led by Ronnie Scott (True Oil) and Matt Loreman (Evercore). Scott’s True Oil started up in 2013 in the Permian Basin and also was backed by Ares.

■ Devon Energy has named Jeff Ritenour as EVP and CFO effective

immediately. Ritenour was SVP of corporate finance,

investor relations and treasurer. He has been with Devon since 2001, serving in a variety of leadership and financial roles.

■ Energy Hunter Resources has named Deirdre M. Sanborn as VP of finance and business development. Sanborn has worked in senior management roles at UBS Investment Bank and Fortis Bank. Energy Hunter is the Permian and Eagle Ford startup of former Magnum Hunter CEO Gary Evans.

■ Energy XXI Gulf Coast has named Douglas E. Brooks as its new CEO. Brooks will also become the seventh board director. Brooks is an industry veteran who was most recently CEO of Yates Petroleum, which was bought by EOG Resources last fall. Brooks replaces John Schiller.

People & Companies

Hilcorp to put expertise to work Continued From Pg 1

Regional Oil & Gas Intelligence November 17, 2015

Serving the local market with drilling activity, permits & deals for sale Volume 02, No. 15

EASTERN COLORADO ACREAGE42,000-Acres Leasehold Position. MORGAN & WASHINGTON - DJ BASINCHEROKEE / MARMATON / ATOKA LTypical Shallow Depths of 6,500-7,500 Ft.100% OPERATED WI; 77.5% NRI Expected Vertical Well IP: 100 BOED OILExpected HZ Well IP: 280 BOED PLAYGross EUR’s: 80 MBOE/Vertical WellL 8439DV

EASTERN COLORADO PROSPECT525-Potential Wells. 42,000-Net Acres. MORGAN & WASHINGTON COUNTIESDJ BASIN DVCherokee, Marmaton, Atoka. 7,000 Ft.100% OPERATED WI; 81.25% NRI DJWell Reserves: 100 MBOE/Well BASINDV 1740L

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Recent Chesapeake Completions in Wyoming (05/22/15-10/08/15)

County Well Name ReservoirTotal

Depth BOPD MCFD

Converse Barton Unit #32-34-67 USA A 1H Niobrara 19,480 1,306 1,296

Converse Rochelle #14-33-69 A 1H Niobrara 14,665 1,223 3,437

Converse Combs Ranch #11-33-70 B 5H Niobrara 17,068 581 2,748

Converse Combs Ranch #11-33-70 B 2H Niobrara 18,331 395 2,345

Converse Combs Ranch #10-33-70 A 8H Niobrara 20,450 286 2,130

Converse Combs Ranch #10-33-70 A 10H Niobrara 19,867 254 2,852

Converse Rochelle #11-33-69 A 1H Niobrara 14,926 1,400 2,953

Converse Combs #29-33-70 ST D SX 16H Sussex 16,834 1,074 3,015

Converse Combs #29-33-70 D SX 12H Sussex 17,102 1,313 3,608

Converse Combs #29-33-70 D SX 14H Sussex 17,754 888 2,298

Converse Combs #29-33-70 D SX 11H Sussex 17,453 845 2,233

Converse Combs Ranch #21-33-70 USA A 4H Niobrara 17,352 1,056 2,714

Converse Combs Ranch #21-33-70 USA A 2H Niobrara 20,058 1,186 2,750

Converse Combs Ranch #16-33-70 USA A 5H Niobrara 16,901 820 4,541

Source: WOGCC & PLS Research

WESTERN SCOUT

Regional Activity (State Data)(10/17/15 to 11/11/15)

Compls PermitsCalifornia – 678Colorado 24 147Nevada – –NW New Mexico 8 5Utah 13 26Wyoming 1 480

Most Active Operators by Permits➊ Aera Energy 185➋ EOG Resources 127➌ Chevron 107

Permits by Formation (by Last Scout)

Formation 11/17 10/27 10/06

Niobrara 216 83 93Codell 157 78 63Diatomite 155 35 17Etchegoin & Chanac 119 12 1Tulare 96 17 62Kern River 59 44 23Lance 53 23 9Etchegoin 50 6 15Parkman 39 21 42Others 392 353 433TOTAL 1336 672 758Sources: CDOC, COGCC, NCMR, NMOCD, UDOGM & WOGCC

Active Rigs Running (Baker Hughes) 73

SandRidge adds North Park Niobrara to portfolioAn entry into a new play by SandRidge

Energy gives the company 136,000 mostly contiguous acres targeting the Niobrara in north-central Colorado’s Jackson County.

The acreage, which is in the North Park Basin between the DJ and Sand Wash basins, has been mostly de-risked by 16 horizontals producing 1,000 boe/d.

The acquisition includes 54 sq mi of 3D seismic coverage and estimated proved reserves of 27 MMboe (82%

oil). SandRidge says the last six wells completed on the acreage had average 30-day rates of 577 boe/d, while previous asset holder EE3 LLC reported two wells

there with 24-hour peak oil rates above 1,000 bo/d.

According to SandRidge, the North Park Niobrara has similar geology to that found in the DJ with five stacked benches at 5,500-9,000 ft, reservoir thickness exceeding 450 ft, more than 55 MMbo/section in place and overpressured reservoir exceeding 0.55 psi/ft.

Chesapeake streamlines in Powder River but reports growthDespite scaling back its Powder River

operations in Wyoming earlier this year, Chesapeake Energy reported a bump in sequential production growth thanks to achieving longer laterals and more frac stages at the same cost as previous wells. Chesapeake says its net Powder River Q3 production averaged ~21,000 boe/d, a 5% increase from Q2.

The company’s YTD completed-well costs average $10.6 million per well 5,900

ft laterals and 22 frac stages, which is the same price as its 2014 wells, but averaged 5,400-ft laterals and 20 frac stages. One of Chesapeake’s recent completions, the

Barton 32-34-67 USA A 1H, was drilled with a 9,500-ft lateral targeting the Niobrara. It was turned to production in October with a 24-hour peak rate of 1,500 boe/d (85% oil).

Saw 5% Q3 production growth from longer laterals, more frac stages.

EE3 reported two wells with 24-hour peak rates above 1,000 bo/d.

Continues On Pg 3

Continues On Pg 3

88 Completions; 751 Permits; 66 Rigs Running.

Western Scout April 18

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PetroScout 20 April 26, 2017

■ Exco Resources has appointed Randall E. King to its board of directors. King will serve on the audit and compensation committees. King is founding member and managing partner of Anderson King Energy Consultants. Prior to that, he was a managing director for Bank of America Merrill Lynch’s oil and gas divestiture business.

■ Live Oak Resource Partners has increased capital commitments to its gas-focused Fund I with total commitments totaling $11.28 million. The Houston-based firm aggregates royalty and mineral acquisitions. Live Oak was founded by Andrew Keene, an energy-focused investment banker with Natixis, and Brandon Meyers, who was a landman with Goodrich, Marathon Oil and Texakoma Operating.

■ Marathon Oil EVP, general counsel and secretary Sylvia J. Kerrigan plans to retire effective July 1 after more than 20 years with the company. Reginald D. Hedgebeth has been hired to take over these roles effective April 24. Hedgebeth joins Marathon from Spectra Energy (now Enbridge), where he was general counsel, corporate secretary and chief ethics and compliance officer.

■ Murphy Oil will promote financial projects VP Christopher D. Hulse as VP and controller effective June 1 to replace Keith S. Caldwell, who will retire later this year after assisting with the transition. Hulse joined Murphy in 2015 as onshore finance VP.

■ Resolute Energy is officially marketing its Aneth field in southeast Utah’s Paradox Basin. Divestment of the asset will turn Resolute into a Delaware Basin pure-play. The company’s Reeves County wells are routinely delivering over 3,000 boe/d IP rates.

■ Rice Energy appointed Kate Jackson to its board of directors effective April 4. She will sit on the nominating and governance and the compensation committees. Jackson was most recently SVP and CTO for RTI International Metals.

People & Companies

Oil volume per well is increasing as well. PDC’s XRL wells now deliver 350,000 bo each, up from 305,000 bo in 2016. For MRL wells, the new curve expects 255,000 bo per well, an increase from 245,000 bo per well previously. Currently, SRL wells yield only 160,000 bo per well, but that is expected to increase when PDC applies enhanced completion techniques. By the end of the year, the company anticipates 40%

CAGR growth in Wattenberg oil volumes.PDC estimates it has 210 XRL locations and 380 MRL locations to

drill. The company benefitted from an acreage swap with Noble Energy last year that will allow it to increase laterals, which will be 15% longer this year at 6,800 ft on average. From 2013-2016, PDC has increased its Wattenberg volumes from 16,000 boe/d to over 57,000 boe/d. It has also gone from drilling 1,100 ft per day to 2,200 ft per day, a 100% improvement.

The company expects to add a fifth Wattenberg rig during 2Q17 and will spud 139 wells, roughly split evenly among SRL, MRL and XRL wells. It will also bring 139 wells online. The company is targeting 30% annual volume growth. Capex is set at $725-775 million, with 60% of that going toward Wattenberg field.

US Oil Sands expects first oil from Utah project US Oil Sands has launched start-up of its PR Spring Project in Utah after

wrapping up the necessary financing. “As we work through this carefully staged start-up plan, we look forward to soon achieving first oil on this first commercial oil sands mining and solvent extraction process,” said CEO Cameron Todd. Start-up involves nine phases.

Operations are expected to be optimized in Q2, targeting safe bitumen recovery, water and solvent recycling and the deposit of clean solids back into the mine for reclamation, the company said. The project is initially expected to produce 2,000 bo/d while a second phase will target up to 10,000 bo/d. The 316-acre permitted project site has 12.5 MMbbl of bitumen in place. McDaniel & Associates Consultants assigned a best estimate of 9.6 MMbbl in recoverable resource. US Oil Sands holds 100% WI in the leases.

Western

PDC’s Wattenberg Wells Flow Increasingly More Oil• Oil volumes per well con�nue to grow • GOR typically stabilizes a�er 18-36 months • MRL and XRL wells represent recent comple�on

design improvements ─ SRL 490 MBoe EUR s�ll based on 2015

comple�on design ─ SRL upside projects 600 MBoe EUR (based

on % improvement similar to MRL and XRL type curves)

• SRL, MRL and XRLs represent 36%, 29% and 35% of 2017 planned Wa�enberg development (TILs)

(1) Oil volumes based on EURs and % oil disclosed at previous Analyst Days

02468

1012

2014 2015 2016 2017e

Wa�enberg Oil Produc�on (MMBbls)

2015 2016 2017 2015 2016 2017 2016 2017

SRL

MRL

XRL

SRL upside w/ new comple�ons

185 175 160

180-200

250 245 255

305

350 Oil Volume per Well(1)

(MBbls)

Source: PDC Energy April 20 Presentation via PLS docFinder www.plsx.com/finder

PDC raises EURs in Wattenberg field Continued From Pg 1

Third-party estimate of 9.6 MMbbl in contingent resource.

For general inquiries, email info@plsx.com

Volume 28, No. 06 21 e&P

Access PLS’ archive for previous E&P news

Alaska to offer 9.95 million acres in June lease sale The Alaska Department of Natural Resources Division of Oil and Gas will offer

onshore and offshore lease sales June 21. The sale encompassing the Alaska Peninsula includes 4.0 million onshore and 1.75 million offshore acres. It includes 1,047 tracts that range in size from 640-5,760 acres. The area stretches from Nushagak Peninsula in the north to Cold Bay in the southwest. The Cook Inlet sales will offer 4.2 million acres over 815 tracts. In-person bids must be submitted by June 19. Public bids open June 21.

The announcement follows a similar one by BOEM earlier this month for federal waters in Cook Inlet. The BOEM lease sale will offer 1.09 million acres over 224 blocks from Kalgin Island in the north to Augustine Island in the south in June.

SRC advances 2017 program on drilling efficiencies Newly branded SRC Energy, formerly Synergy, is accelerating its drilling and

completion pace for the year as a result of several field-level efficiencies. The Wattenberg driller is adding 14 wells to its drilling program for 116 total and nine wells to its

completions for a total of 104 wells. No change is expected to capital guidance.Increased operational pace

and strong well performance have led to a production guidance increase. SRC anticipates full-year volumes of 25,000-27,000 boe/d. The company’s 1Q17 average volumes were 17,743 boe/d (64% liquids). It brought 25 wells to sales with 15 more wells on deck. SRC is running two rigs and expects to maintain that pace throughout the year.

“Our team’s ability to execute is being demonstrated every day and completion of the Evans pad exemplifies our ability to complete complex projects on time and within budget,” CEO Lynn Peterson said. “While production from the wells is limited, we are very encouraged by early results. Given the complexity of the geology, the pad’s unique layout, and the fact that nine of the 22 wells have measured depths of approximately 20,000 ft each, I want to commend our entire team for their efforts.”

Western ■ Sanchez Petroleum Partners COO

Patricio D. Sanchez was promoted to the additional position of president. He also serves at affiliates Sanchez Oil & Gas as co-president and Sanchez Energy as EVP.

■ Talos Energy welcomes Carl Comstock as a senior land advisor. Prior

to joining Talos, Comstock served as

the VP of land and business development with Tana Exploration Co.

■ Templar Energy appointed Joe Pukaite as its SVP and CFO effective April 1. Pukaite comes from Freeport-McMoRan Oil & Gas, where he was treasurer from 2013-2017. He began his career as an engineer at Schlumberger.

■ Triangle Petroleum chief accounting officer Douglas Griggs resigned to pursue other career opportunities. Triangle also expanded its board from five to six members, adding Northwestern University clinical strategy professor James B. Shein.

■ Unit Corp. named Frank Young as an EVP at subsidiary Unit Petroleum, which he joined in June 2007 as VP of the company’s central division after more than 16 years with Anadarko.

■ Viper Energy Partners named Spencer D. Armour III to its board, where he will serve on the audit committee.

Armour replaces W. Duncan Kennedy, who has resigned. Armour has more than 30

years of executive and entrepreneurial experience in the energy services industry and currently serves as president of Midland-based PT Petroleum.

■ W&T Offshore announced new VP, general counsel and secretary Shahid A. Ghauri, who succeeds retiring Thomas

F. Getten. Ghauri joined the company in March after being partner at Jones Walker. He

was also assistant general counsel of BHP Billiton. Getten had been with W&T since 2006. The company promoted Janet Yang to VP of corporate and business development from her previous role as director of strategic planning and analysis. James Hersch was promoted to VP of geosciences from director.

People & Companies

PLS expands consulting practicePLS Energy Advisors is expanding with the addition of Martin Buckley and

Myron Boots, who founded Buckley & Boots in 1987. B&B has worked with major and independent oil companies, law firms and investment banks over the last 30 years to provide reserve estimates, management consulting and M&A advice. The addition of B&B expands the service offerings of PLS, which has long offered traditional mid-market

divestment services and specialized buy-side services.Now, PLS Energy Advisors can provide strategic management

consulting, engineering and geologic consulting, independent valuations and fairness opinions, and litigation support and expert witness testimony. “I am excited to team up with Martin and Myron, whose technical expertise, transaction depth and management experience enhance PLS Energy Advisors’ ability to offer clients custom technical solutions,” PLS founder Ronyld Wise said.

B&B’s Martin Buckley added, “The relationship with PLS allows us to take the work we have been doing for clients for the past 30 years to a new level by utilizing PLS’ industry content, technology, and global client base.”

Buckley holds an MBA from the University of Texas, an MS in engineering management from the University of Alaska and a BS in geology from Mississippi State University. Boots has a BS in mechanical engineering from the University of North Dakota and holds professional engineering registrations in Texas and Colorado.

Alaska

Developments & Trends

Will drill 14 more wells, complete nine more wells than expected.

Onshore sale in Alaska Peninsula; offshore covers Cook Inlet.

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PetroScout 22 April 26, 2017

NEW MEXICONEW MEXICO PROSPECT12,500 Gross and 9,200 Net Acres.RIO ARRIBA & SANDOVAL COUNTIESSAN JUAN BASIN DVUnconventional Dakota & Mancos PlayAcreage Relatively Undrilled & VirginPressure Environment. SAN JUANVertical & Horizontal UpHole PotentialACREAGE FOR SALEAlso Liquid Rich PC Potential.Most Leases Expire 2021-2024.DV 2726L

NORTH DAKOTABOWMAN CO., ND PROPERTY1-Unit. 50,000-Acres.WILLISTON BASIN LCEDAR HILLS ANTICLINERed River C & D Benches ROCKIESDevelopment Has Been Conventional.OPERATED WI AVAILABLEL 2710PP

UTAHDAGGETT CO., UTAH PROSPCET~10,049-Total Acres.NORTHERN UTAH DVPrimary Obj: Dakota & Frontier FormationsSecondary Obj: Entrada & Navajo SandsDepths - 15,000 to 17,000 Feet. NORTHERNRecoverable Potential: 7-12 MMBO -- UTAH-- 50-70 BCFDV 4573

WEST-CENTRAL UTAH OIL PROSPECT24-Potential Wells. >49,000-Acres.JUAB & MILLARD COUNTIESShallow Drilling Depths At <6,000 Ft. DVMultiple Drilling Opportunities Along Fairway.Seismic, Proprietary Geophysics & --Geochemistry, Subsurface & Gravity DataLeases Can Deliver 87.5% NRI SHALLOWWell Reserves: 10+ MMBO/WellProject Reserves: 84 MMBODHC: <$1,500,000; Completion: <$800,000DV 1190L

WYOMINGBIG HORN CO., WY PROSPECT630-Acre Federal Lease.BIGHORN BASIN4 POTENTIAL PAY ZONES DVObj 1: Phosphoria. 3,590 Ft.Obj 2: Tensleep / Madison. 4,115 Ft.Subsurface Geology Data Available TENSLEEP100% OPERATED WI; 80% NRITotal Project Reserves: 10.7 MMBODHC: $350,000; Completion: $500,000DV 5159L

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What the Analysts are Saying About E&P Carrizo Oil and Gas (CRZO; $29.24-Apr. 5; Buy; $38 PT)

Limited commentary on the 3ROC assets which are for sale in the Delaware Basin directly offset CRZO. Management hopes to be a strong bidder on the package. In the Eagle Ford, CRZO may test the Austin Chalk later this year. Management also

believes that there is a significant misconception of the performance of its Eagle Ford wells (especially its stack-stagger pilots) largely due to recent studies based on state data (oil production is reported at the

lease-level in Texas, making accurate well-level analysis nearly impossible). CRZO noted that it would have significantly missed its 2016 production targets if its stack-stagger pilots were actually underperforming expectations (as suggested by studies utilizing public state data). —Seaport Global Securities

Chesapeake Energy (CHK; $5.39-Mar. 29; Buy)Multiple catalysts on the horizon, attractive valuation keeps us constructive.

New presentation highlights CHK’s first Turner well in the PRB with an IP-24hr rate of 2,325boepd (78% oil) on a 7,100’ lateral. The company has now successfully

tested the Niobrara and Turner zones and Mowry, Sussex, and Parkman tests are on deck. In the MidCon, three new

Meramec/Osage wells continue to prove up prospectivity in Major/Dewey County. With 45 Wedge/20 PRB TILs in 2017, we expect significant progress towards oil inventory expansion during the year. —Tudor, Pickering, Holt & Co.

Diamondback Energy (FANG; $100.55-Apr. 20; Buy; PT: $135)Significant Delaware cost savings with revised completion recipe. We think the

Q1 update will provide important color on FANG’s initial approach to developing its now formidable 101K net acre position in the Southern Delaware Basin. To this point,

we believe management will be able to tout that the Mclntyre State 38 2H, FANG’s first operated completion on the acquired

Brigham assets was completed for a cost ~$400/ft lower than the well costs as the time of the acquisition. This equates to a ~44% savings and $4MM/well in total assuming a 10K ft. lateral. As important, we think management will also be able to claim that revised completion recipe didn’t compromise well performance as oil production meaningfully outperformed offsetting wells. —Seaport Global Securities

EOG Resources (EOG; $99.76-March 1; Buy)The company’s Enhanced Oil Recovery (EOR) pilots are yielding very promising

results with huge implication for an ultimate recovery factor in this trend… The implication is that ~30% more oil can be recovered after primary recovery; this math

can become very staggering, in our view. If successful, this breakthrough concept can lead to significant resource exposure for EOG. We continue to be impressed and amazed by EOG’s ability to reinvent plays. We look forward to

more breakthrough results from the company’s South Texas Projects. —Wunderlich

Gulfport Energy (GPOR; $15.44-Apr. 18; Outperform)All eyes likely will be on SCOOP well results on enhanced completions with

initial results expected in the coming weeks. 1Q17 production came in at 849.6 MMcfe/d, 2% above our 829.6 and 1% above the Street's 839.7 MMcfe/d, driven by the Utica at 742 MMcfe/d vs. our 732 MMcfe/d while SCOOP

production came in at 81.3 MMcfe/d, 3% above our 78.8 MMcfe/d. —Wells Fargo

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Volume 28, No. 06 23 e&PWYOMING

CARBON CO., WY PROSPECT13,000-Total Acres. 2-Prospects.HANNA BASINObj 1: Tensleep/Sundance. 8,500 Ft. DVObj 2: Frontier/Niobrara. 10,000-14,000 Ft.2D Seismic, Subsurface Geology, ---- Geophysics & Geochemistry Data HANNA100% OPERATED WI; 80% NRI BASINContiguous Acreage.Est Net Rsrvs: 400-1,500 MBOE/WellEst Project Rsrvs: 120 MMBOReference Percy Creek On Youtube.Compl: $1,000,000. Well Cost: $2,100,000DV 4595L

HOT SPRINGS CO., WY PROPERTY3-Active Wells. 1-Inj Well. 1,758-Acres.CENTENNIAL FIELD20 Additional Locations Available. PPObj 1: Phosphorra. 1,650 Ft.Obj 2: Madison. 2,500 Ft.Discovered 1992 w/ 1 Water Supply Well.Undeveloped Oilfield w/ Madison Potential.100% OPERATED WI; 76-80% NRIGross Prod: 18 BOPD & 137 BWPD SHALLOWNet Production: 14 BOPD UPSIDECash Flow: $33,600/MonthRecoverable Reserves: 2.0 MMBOPP 1265DV

ARIZONACOCONINO CO., AZ PROSPECT~200,000-Total Acres.CHUAR BASINTargeted Vertical Depth: 6,000+ Feet DVLimited 2D Seismic Data Available75% WORKING INTEREST; 78% NRIProject Reserves: 300-600 MMBO CHUARNear Major Gas Pipelines. BASIN10-Year Leases Acquired 2007-2011DHC: $1,200,000; Compl: $800,000DV 4707L

CALIFORNIACALIFORNIA GAS PROSPECTS2-Drill Ready Onshore Wells.SACRAMENTO BASINConventional Sandstone Reservoirs. DVDrilling Depths: <6,500 to 11,500 Ft.Extensive 2D & 3D Seismic & Wells.Up To 100% WI AVAILABLE 3-D PROSPECTSOPERATIONS NEGOTIABLELow Operating CostMulti-Tcf Conventional GasDry Hole Cost: <$4,000,000-$8,000,000DV 4439

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What the Analysts are Saying About E&P Marathon Oil (MRO; $17-March 21; Equal Weight)

Increased focus on unconventional assets. MRO will look much more like peers as it completes acquisitions. We are raising our enterprise value target multiple from 6.25x to 6.75x 2018 E PICF to reflect a much-improved opportunity set. We

remain Equal Weight but are trimming our price target by $1 to $17 to reflect our lower 2018 cash flow forecast partially offset by the higher

target multiple and improved net debt outlook. We believe the transition to resource plays is largely done. MRO will likely ramp from 1 to 6 Delaware rigs over the next 9-12 months. —Barclays

Ring Energy (REI; $12.19-Apr. 18; Buy; PT: $20)On the heels of a solid ops update which unveiled encouraging rates from REI’s

initial eight hz. San Andres tests in the CBP (exceeded our expectations by >36%), REI more than doubled its hz. footprint in the CBP by acquiring >33K acres for $16.6MM.

We were most excited to learn that REI is drilling/completing wells at a considerably faster rate than it initially anticipated, and that the company could drill as many as 30+ hz. wells in 2017. If we assume REI ramps to 3

rigs by the beginning of FY19 (vs. ~2 rigs in our model) and if the company’s average San Andres well carries ~59 boe/ft. EUR potential, then: (1) our estimated average project IRR jumps to >200% (vs. ~125%); (2) our debt-adjusted production forecast through FY20 increases to >80% (vs. ~49%), which results in eye-popping multiple compression (~12.3x FY17E EV/EBITDA down to ~1.5x by FY20E), and; (3) our NAV would increase to >$30/share. —Seaport Global Securities

SRC Energy (SRCI; $8.23-Apr. 20; Buy)1Q17 production and prices beat, raising estimates on accelerated plan. The

production beat is positive albeit partially offset by a realized price shortfall and increased 2017 capex guidance. SYRG remains on track to generate best-in-class returns and growth with one of the best balance sheets in our peer group. We expect the stock to outperform as the SRCI executes its plan over the next 12 months.—Stifel

WildHorse Resource Development (WRD; $12.34-March 31; Buy)WRD closed the Clayton Williams Energy Eagle Ford acquisition and went

public in mid-December 2016. Since then, it raised $350mm of high-yield debt, did ~ $15.6mm of bolt-on acquisitions in the Eagle Ford, and ramped up its rig count from one to six. WRD reiterated its 2017 capex and 36% production growth target and is on track to generate even more growth and become self-

funding in 2018. We reiterate our Buy rating on this high-growth name with lots of upside potential. —Wunderlich

Winter looks to be behind us as ND experiences another month of prod’n increasesNorth Dakota oil production rose 53mbopd to 1,034mbopd in February, returning

production to the same level as this past November before the ~90mbopd decrease that came at the end of 2016. The production increase contrasts the trend set the past two years of February m/m production decreases of -3.4mbopd in 2016 and -14.1mbopd in 2015. Signs look to be positive for Bakken producers as crude diffs have tightened, with Bakken crude trading above WTI and weather unlikely to impact production until next winter. Expect in-basin producers like CLR, OAS and WLL to begin to see this flow through as companies report relatively soon. —Tudor, Pickering, Holt & Co.

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PetroScout 24 April 26, 2017

MOSTLY APPALACHIA/EASTERNTRENTON BLACK RIVER LEASEHOLD30,000-Acre Leasehold.SOUTHEAST MICHIGAN DVNORTHERN OHIO2D & 3D Seismic Data Available TRENTONDRILL TO EARN WORKING INTERESTReserve Potential: 50+ MMBODV 5690

MOSTLY TEXASTEXAS CONVENTIONAL PROPERTIES22,343-Gross Acres. 18,192-Net Acres.PERMIAN, NORTH & SOUTH TEXASSan Andres, Yates, Seven Rivers, Glorieta, PPClearfork, Palo Pinto & Canyon/Cisco SandsProven Upside From Shallow Horizontal MULTI-Development In North Texas. REGIONVarying Operated WI, NonOp WI, RI & ORRINet Production: 979 BOED (70% Oil)Expected 12-Mn Cash Flow: $550,000/MnSummary Listing To 3 Separate PackagesAGENT WANTS OFFERS MAY 11PP 9850PKG

BALANCED PORTFOLIOMULTISTATE PROSPECTS40-Potential Wells. 6,000+Acres.ARKANSAS & MISSISSIPPILEE, PHILLIPS, CLARKDALE, TUNICA DVOUACHITA OVERTHRUST TRENDObj 1: Atoka/Morrow. 5,000 Ft.Obj 2: Atoka/Viola. 8,500 Ft. ATOKA2D Seismic, Subsurface & Geophysics75% WI; 75% NRI; Operations AvailablePossible Triangle Zone.Expected IP (M): 500 BOPDExpected IP (V): 10 MMCFDGravity Mag, HC Maturity/Migration ----Analysis, Balanced Cross Sections.Est Well Rsrvs: 5-10 BCFEst Proj Rsrvs: 100 MMBO & 2 TCFDHC: $1,000,000+; Compl: $200,000DV 3957

CALIFORNIAKERN CO., CA JV OPPORTUNITY1,100-Acres.FRUITVALE FIELD DVTarget Depth Of <4,300 FeetPermits In Place w/Development ReadySEEKING JV PARTNER FRUITVALE>117 PUD Locations. Existing PDP.DV 2945

SAN JOAQUIN BASIN PROSPECT>1,000,000-Net Acres.KERN, KINGS & FRESNO COS., CAMulti-Stacked Pay Potential DVTarget Depths: 4,000-14,000 Ft.Subsurface Geology, Geophysics, -- Geochemistry, 2D & 3D Seismic Data OPERATIONS NEGOTIABLE SACRAMENTOP50 Prospective Resource:100 MMBOEDHC: $750k-$7.0MM; Compl: $100k-$2.0MMDV 2731

SAN JOAQUIN BASIN PROSPECTS9 Conventional Exploration TargetsKERN CO., CALIFORNIA DVBELRIDGE & LOST HILLS AREACitrus, Cassini & Thorndyke ProspectsAdvanced 3D Seismic ProcessingSEEKING JV PARTNERS JOINT VENTURETotal Potential: 50-80 MMBOEExposure to 170 MMBOE (Recoverable)DV 2953

WANTEDWANTED: TEXAS OIL FIELDSSeeking Producing Assets.SHALLOW & CONVENTIONAL WExperienced w/ Depths To 5,000’.Needs Long Reserve Life. WANTEDRequires Field Optimization Potential.MUST DELIVER OPERATIONSWants Net Volumes 250-1,000 BOPD.W 5978PP

WANTED: PERMIAN OPERATED WIProducing Conventional Reserves.ASSETS MUST BE PDP WPermian Operator Seeks To Acquire----Long-Lived Producing Reserves. PDPSEEKING OPERATED WITransaction Size: $1.0MM-$40.0MMW 5468PP

WANTED: MARGINAL PRODUCTIONTEXAS, LOUISIANA, OKLAHOMA,& KANSAS WBuyer Seeks To Take Over Wells----With Upcoming Plugging Liability. WANTEDMUST BE OPERATED WILOOKING FOR OUTRIGHT PURCHASEW 5422PP

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