Yangarra Announces Second Quarter 2014 Financial and Operating Results

CALGARY, Aug. 13, 2014 /CNW/ - Yangarra Resources Ltd. ("Yangarra" or the "Company") (TSX:YGR) announces its financial and operating results for the three and six months ended June 30, 2014.

Second Quarter Highlights

Production for the quarter was 2,606 boe/d (51% oil and NGL's), a 32% increase from the same period in 2013.  The production was negatively impacted by turn-around season at various third party facilities in Central Alberta.  A total of 60,000 boe (650 boe/d for the quarter) of production, representing almost $3 million of cash flow, was shut in while the various facilities were under repair. 

  • Oil and gas sales including royalty income were $14.1 million with funds flow from operations of $8.2 million ($0.15 per share - basic). This was an 82% and 26% increase from the same period in 2013, respectively with the spread in funds flow from operations between the two periods primarily a result of the monthly settlement of commodity contracts.
  • Earnings before interest, taxes, depletion & depreciation, amortization and changes in the fair value of commodity contracts ("EBITDA") was $8.6 million, compared with $6.8 million in the same period of 2013.
  • Operating costs were $6.92 per boe and transportation costs were $1.88 per boe, an increase of 7% and 46%, respectively, from the same period in 2013.
  • Operating netback of $38.23 per boe, a 5% decrease from the $40.30 per boe reported in the same period of 2013.  Field net backs (operating netback excluding commodity contracts) were $47.04 an increase of 31% from the same period in 2013.
  • G&A costs of $1.36 per boe, which is a 31% decrease from the second quarter of 2013.
  • Royalties were 7% of oil and gas revenue (6% when the commodity contracts are excluded).
  • Total capital expenditures were $19.4 million
    • The Company successfully drilled or participated in 9 gross (4.8 net) wells during the second quarter of 2014 and the Company expects to drill a total of 6 gross (5.5 net) wells in the third quarter.
  • As at June 30, 2014, the Company had current bank debt and working capital deficit, excluding fair value of commodity contracts and non-cash flow-through share premium obligations, of $41.0 million compared to $44.6 million at December 31, 2013.
    • The annualized second quarter debt to cash flow ratio was 1.3 : 1.
  • Graduated from the TSX Venture Exchange to the Toronto Stock Exchange on June 27, 2014.
  • Completed a 3 to 1 Share Consolidation on May 30, 2014.

Operations Update

Cardium

During the first half of 2014 the Company drilled 4.0 gross (4.0 net) wells in South Willesden Green; however, third party facility constraints only allowed full production from these wells as of June 1, 2014 upon commissioning of additional compression.  The wells were drilled with 1 mile laterals, 18 stage open-hole completions using slick water frack's and 540 tonnes of sand per well with resin coated sand tailed into each stage to reduce crushing.  Average cost per well to drill and complete was $2.7 million and the average IP-30 for the four wells was 195 boe/d (65% Oil and NGL's). The internal type curve IP-30 is 190 boe/d (75% Oil and NGL's).  No further Cardium wells are planned in this area by the Company this year.

In South Ferrier, Yangarra continued its strategy of drilling where it has gas processing capacity (100% owned Cow Lake 16-2-38-8W5 facility) by drilling 3.0 gross (2.2 net) wells during the second quarter. Costs were slightly higher than normal at $3.5 million for drill and complete as the wells were drilled over breakup (approximately $200,000 incremental costs per well). On the third well the Company performed a 24 stage completion rather than an 18 stage completion and is evaluating the impact of the incremental stages.  The average IP-30 for the three wells was 367 boe/d (60% Oil and NGL's). The IP-30 on the internal type curve is 321 boe/d (75% Oil and NGL's).  Yangarra's Cow Lake facility transports natural gas to the Keyera Strachan plant for deep cut NGL processing; however the Strachan plant was down for 29 days from May 22 until June 18, 2014.   The Company has no further drilling plans until 2015 in this area as the Cow Lake plant is at capacity.

In Central Willesden Green, the Company drilled a total of 4 gross (3.9 net) wells during the first half of 2014, utilizing the normal two well pad strategy. Two of the wells were on-stream at the end of March and two were on-stream in July.  The first pair were completed with 18 stage fracks and the second pair with 24 stage fracks using a zipper approach of alternating stages between the two wells on the pad.  Due to screen out, only 12 stages in each of the second pad wells were zipper fracked and the balance of the stages were performed sequentially.  At this point it is too early to determine if the incremental stages or the zipper frack will result in a material improvement to overall well economics.  Average cost per well to drill and complete was $2.6 million and the average IP-30 for the four wells was 230 boe/d (85% Oil and NGL's), the internal type curve IP-30 is 190 boe/d (75% Oil and NGL's). Due to mono-bore drilling, the size of the tubing is limited to 2 3/8″ and consequently the size of the bottom hole pump ("BHP") is limited to 150 bbl/d.  Fluid levels are still very high on all four wells and as a result the Company expects shallower declines than normal.   These wells produce into the Company facility (50% WI) at 2-4-42-7W5 with the liquids rich natural gas then sent to Centrica's deep cut Ferrier plant for NGL recovery.  The Centrica plant was down for a turn-around for one week during May.  An additional four wells are planned for this area in 2014 by the Company.

In North Willesden Green, Yangarra participated in 6.0 gross (1.0 net) wells during the first half of 2014 with the wells currently on test and expected to be on-stream shortly.  Yangarra plans to drill 4 gross (2.5 net) additional wells in the area in the second half of 2014.  The Company is also participating in the construction of a 50.0 mmcf/d compression facility (5.54 % working interest) which is scheduled to be commissioned in October of 2014.  Two of the planned wells will produce into the new facility and two will produce into an existing third party facility.

Glauconite

The Company commenced drilling on a two well pad targeting the Glauconite oil window in the Medicine River area (39-5W5) late in the second quarter of 2014.  Drilling was completed on the second well August 4th and completion operations commenced on the two wells August 6th.  Upon evaluation of the well production results, two more wells are planned for 2014.

Duvernay Update

Yangarra's strategy is to wait for industry to de-risk the play and to continue the lands to 2020 in the most economical manner possible.  The Company will use the $5.0 million of flow through funds that were raised in 2013 to fund the continuation drilling in 2014.  A drilling rig has been contracted by the Company that is currently drilling a Duvernay well nearby for another operator.  Two locations are ready to license and long lead materials have been acquired. The Company's first location will be confirmed prior to mobilizing the rig in order to leverage the most recent industry results.

North Block 54 sections (54 net)

Yangarra has conducted an in-depth review of its acreage, using geo-chemical, petro-physical and geo-mechanical analyses of offset wells and proprietary reservoir studies.  The Company estimates that the Duvernay in the northern block has a net pay ranging from 20 to 24 meters thick, is over-pressured (~19 kPa/m), in the liquids rich window and likely naturally fractured.  The Company further estimates that OGIP ("Original Gas in Place") for this block ranges between 40 and 50 Bcf per section together with significant condensate and NGL volumes.

South Block 7 sections (7 net)

The South block has been reviewed by the Company and delineated by several horizontal wells drilled by senior operators immediately adjacent to the Company's acreage.  The Company has estimated a net pay of 35 meters, in an over-pressured reservoir (~20 kPa/meter) and liquids rich fairway.  The Company estimates that OGIP ("Original Gas in Place") for this block ranges between 70 and 100 Bcf per section together with significant condensate and NGL volumes.

Guidance Update

The Company expects second half production of 3,900 boe/d and cash flow of $26 million, however due to the turn-arounds in the second quarter the full year production is now forecast to be 3,300 boe/d with cash flow of $47 million.

Future Drilling Inventory and Well Economics

The Company revised its future drilling inventory in the Cardium and Glauconite to account for recent property acquisitions.

Cardium

  Locations

147 gross (107 net)

  Locations booked in 2013 Reserve Report

35 gross (29 net)

  Drill, Complete and Equipping

$2.7 million – $3.2 million

Average: $2.9 million

  NPV10 (1) ($90/bbl & $4.00/mcf)  

$2.4 million – $4.7 million

Average: $3.3 million

  IRR – Half cycle before tax

67% – 172%

Average: 106%

  Payout

8 months – 16 months

Average: 13 months



(1)

Present value of future cash-flow, discounted at 10%, net of Drill, Complete and Equipping

costs.

Glauconite

  Locations

41 gross (34 net)

  Locations booked in 2013 Reserve Report

11 gross (8 net)

  Drill, Complete and Equipping

$3.0 million – $3.5 million

Average: $3.3 million

  NPV10 ($90/bbl & $4.00/mcf) (1)

$2.9 million – $6.3 million

Average: $3.7 million

  IRR – Half cycle before tax

75% – 188%

Average: 122%

  Payout

8 months – 13 months

Average: 11 months



(1)

Present value of future cash-flow, discounted at 10%, net of Drill, Complete and Equipping

costs.

Financial Summary









2014

2013


Six Months Ended


Q2

Q1

Q2


2014

2013

Statements of Comprehensive Income (Loss)







Petroleum & natural gas sales and royalty income

$

14,106,137

$

16,008,396

$

7,747,389


$

29,571,278

$

14,265,770

Net income (loss) for the period (before tax)

$

3,821,726

$

1,202,068

$

2,923,438


$

5,023,794

$

2,530,152








Net income (loss) for the period

$

2,851,233

$

719,450

$

2,082,942


$

3,570,683

$

1,823,518

Net income (loss) per share - basic and diluted

$

0.05

$

0.03

$

0.05


$

0.07

$

0.04








Statements of Cash Flow







Funds flow from (used in) operating activities

$

8,180,361

$

10,459,692

$

6,480,689


$

18,640,053

$

11,294,871

Funds flow from (used in) operating activities per share -

basic and diluted

$

0.15

$

0.21

$

0.16


$

0.36

$

0.03

Cash from (used in) operating activities

$

6,386,075

$

6,008,779

$

8,183,515


$

12,394,854

$

12,636,393








Statements of Financial Position







Property and equipment

$

187,940,259

$

171,336,343

$

130,846,089


$

187,940,259

$

130,846,089

Total assets

$

212,513,340

$

195,777,835

$

144,353,167


$

212,513,340

$

144,353,167

Working Capital (deficit), excluding MTM on commodity

contracts and flow-through premium obligation

$

41,022,416

$

55,822,090

$

39,989,839


$

41,022,416

$

39,989,839

Non-Current Liabilities

$

19,289,460

$

18,246,628

$

13,197,200


$

19,289,460

$

13,197,200

Shareholders equity

$

126,644,146

$

97,025,179

$

81,826,383


$

126,644,146

$

81,826,383








Weighted average number of shares - basic

53,558,093

49,136,780

40,570,574


51,359,650

40,570,574

Weighted average number of shares diluted

55,898,462

50,108,392

40,574,059


51,359,650

40,570,574















Company Netbacks ($/boe)









2014

2013


Six Months Ended


Q2

Q1

Q2


2014

2013








Sales Price

$

58.53

$

62.37

$

42.52


$

60.51

$

41.33


Royalty income

0.97

1.25

2.01


1.11

2.13


Royalty expense

(3.66)

(3.73)

(1.52)


(3.69)

(1.56)


Production costs

(6.92)

(6.49)

(5.84)


(6.70)

(6.88)


Transportation costs

(1.88)

(1.32)

(1.29)


(1.59)

(1.13)

Field operating netback

47.04

52.08

35.88


49.63

33.89


Commodity contract settlement

(8.81)

(6.85)

4.42


(7.80)

3.60

Operating netback

38.23

45.23

40.30


41.83

37.49


G&A and other (excludes non-cash items)

(1.36)

(1.30)

(1.96)


(1.33)

(2.23)


Finance expenses

(2.78)

(3.33)

(2.00)


(3.06)

(2.11)

Cash flow netback

34.10

40.60

36.34


37.44

33.14


Depletion and depreciation

(16.41)

(16.53)

(18.38)


(16.47)

(18.31)


Accretion

(0.17)

(0.16)

(0.13)


(0.17)

(0.22)


Stock-based compensation

(0.46)

(1.63)

(1.15)


(1.06)

(0.61)


Unrealized gain (loss) on financial instruments

(0.94)

(17.50)

(0.63)


(9.46)

(6.67)


Deferred income tax

(4.09)

(1.92)

(4.61)


(2.97)

(2.05)

Net Income netback

$

12.03

$

2.86

$

11.43


$

7.31

$

5.29








Operations Summary

Net petroleum and natural gas production, pricing and revenue are summarized below:









2014

2013


Six Months Ended


Q2

Q1

Q2


2014

2013








Daily production volumes








Natural gas (mcf/d)

7,306

7,572

5,915


7,438

5,505


Oil (bbl/d)

1,003

1,036

492


1,019

497


NGL's (bbl/d)

309

413

339


361

315


Royalty income









Natural gas (mcf/d)

302

359

832


329

766



Oil (bbl/d)

1

0

1


1

2



NGL's (bbl/d)

26

25

49


25

48


Combined (boe/d 6:1)

2,606

2,796

2,005


2,700

1,906








Revenue







Petroleum & natural gas sales - Gross

$

13,876,299

$

15,694,979

$

7,747,389


$

29,571,278

$

14,265,770

Royalty income

229,838

313,417

366,609


543,255

735,947

Commodity contract settlement

(2,088,038)

(1,723,339)

805,711


(3,811,377)

1,236,128

Total sales

12,018,099

14,285,057

8,919,709


26,303,156

16,237,845








Royalty expense

(867,916)

(937,556)

(276,865)


(1,805,472)

(537,957)

Petroleum & natural gas sales - Net

11,150,183

13,347,501

8,642,844


24,497,684

15,699,888








Change in fair value of contracts

(222,122)

(4,403,102)

(114,736)


(4,625,224)

(2,300,219)

Total Revenue - Net of royalties

$

10,928,061

$

8,944,399

$

8,528,108


$

19,872,460

$

13,399,669









Working Capital Summary

The following table summarizes the change in working capital during the six months ended June 30, 2014 and year ended December 31, 2013: 






2014

2013




Working capital (deficit) - beginning of period (1)

$

(36,794,243)

$

(36,301,842)




 Funds flow from operating activities

18,640,053

25,648,666

 Additions to of property and equipment & E&E Assets

(41,434,437)

(47,485,106)

 Issuance of shares

26,371,337

13,593,273

 Issuance of Subordinated Debt

(7,786,632)

7,786,632

 Other Debt

(18,494)

(35,866)

Working capital (deficit) - end of period (1)

$

(41,022,416)

$

(36,794,243)




Subordinated Debt Outstanding

$

-

$

(7,786,632)




Total Debt

$

(41,022,416)

$

(44,580,875)




Credit facility limit

$

70,000,000

$

45,000,000

Subordinated debt facility limit

$

20,000,000

$

20,000,000






(1)

Excludes fair value of commodity contracts and non-cash flow through premium obligations

Capital Spending

Capital spending is summarized as follows:









2014

2013


Six Months Ended

Cash Additions

Q2

Q1

Q2


2014

2013








Land, acquistions and lease rentals

$

1,037,155

$

972,133

$

(226,665)


$

2,009,288

$

833,615

Drilling and completion

15,973,721

18,373,738

1,190,051


34,347,461

9,226,916

Geological and geophysical

368,657

320,228

135,526


688,884

169,204

Equipment

2,056,234

2,324,948

2,724,863


4,381,182

4,604,677

Other Asset Additions

9,462

(1,839)

(115,174)


7,622

136,780


$

19,445,229

$

21,989,208

$

3,708,601


$

41,434,437

$

14,971,192






















Exploration & evaluation assets additions

$

-

$

-

$

-


$

2,461,506

$

-

Corporate Presentation

An updated corporate presentation is available on the Company's website.  www.yangarra.ca

Disclosure Items

The Company's financial statements, notes to the financial statements and management's discussion and analysis have been filed on SEDAR (www.sedar.com) and are available on the Company's website (www.yangarra.ca). 

Natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated.  The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore Boe's may be misleading if used in isolation. References to natural gas liquids ("NGLs") in this news release include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (Boe).  One ("BCF") equals one billion cubic feet of natural gas.  One ("Mmcf") equals one million cubic feet of natural gas.  Operating netbacks are calculated as revenue from all products less operating costs.

Forward looking information

Certain information regarding Yangarra set forth in this news release, including management's assessment of future plans, operations and operational results may constitute forward-looking statements under applicable securities law and necessarily involve risks associated with oil and gas exploration, production, marketing and transportation such as loss of market, volatility of prices, currency fluctuations, imprecision of reserves estimates, environmental risks, competition from other producers and ability to access sufficient capital from internal and external sources.  As a consequence, actual results may differ materially from those anticipated in the forward-looking statements.

All reference to $ (funds) are in Canadian dollars.

SOURCE: Yangarra Resources Ltd.

For further information: Please contact James Evaskevich, President & CEO 403-262-9558.


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